Treating fluid comprising hydrocarbons, water, and polymer

ABSTRACT

Embodiments of treating fluid comprising hydrocarbons, water, and polymer being produced from a hydrocarbon-bearing formation are provided. One embodiment comprises adding a concentration of a viscosity reducer to the fluid to degrade the polymer present in the fluid and adding a concentration of a neutralizer to the fluid to neutralize the viscosity reducer in the fluid. The addition of the concentration of the viscosity reducer is in a sufficient quantity to allow for complete chemical degradation of the polymer prior to the addition of the concentration of the neutralizer in the fluid such that excess viscosity reducer is present in the fluid. The addition of the concentration of the neutralizer is sufficiently upstream of any surface fluid processing equipment to allow for complete neutralization of the excess viscosity reducer such that excess neutralizer is present in the fluid prior to the fluid reaching any of the surface fluid processing equipment.

CROSS REFERENCES TO RELATED APPLICATIONS

This application claims benefit of U.S. Provisional Application No.62/748,897, filed Oct. 22, 2018, which is hereby incorporated herein byreference in its entirety

TECHNICAL FIELD

The present disclosure is generally related to treating a fluid,especially treating a fluid comprising hydrocarbons, water, and polymer,such as in enhanced oil recovery (EOR) in the hydrocarbon industry.

BACKGROUND

A fluid is sometimes injected into a hydrocarbon-bearing formation toimprove hydrocarbon production. For example, enhanced oil recoveryincludes the injection of a fluid containing a polymer into theformation. The formation can be flooded with the polymer to increase theviscosity of the water and control (i.e., decrease) the mobility ofwater that is injected into the formation during the flood, and thus,increase sweep efficiency. The polymer flood, as it is often called, mayincrease the rate and/or total volume of produced hydrocarbons. In atypical polymer flood, polymer from a source is mixed on-site with afluid to form the injection fluid, and then the injection fluid isinjected into the formation through an injection wellbore. The mixingprocess can vary depending on the initial state of the polymer as it issupplied. Unfortunately, the fluid being produced from the formation viaa production wellbore, often referred to as produced fluid, may containpolymer from the injection fluid that negatively impacts surface fluidprocessing equipment. Furthermore, the fluid containing the polymer mayalso negatively impact downhole fluid lifting equipment in theproduction wellbore. For example, the negative impact of the polymer mayinclude polymer scaling,

Therefore, a need exists in the art for an improved manner of treating afluid, especially a fluid comprising hydrocarbons, water, and polymer,such as in enhanced oil recovery in the hydrocarbon industry.

SUMMARY

Embodiments of treating fluid comprising hydrocarbons, water, andpolymer being produced from a hydrocarbon-bearing formation via aproduction wellbore are provided herein. One embodiment of a method oftreating fluid comprising hydrocarbons, water, and polymer beingproduced from a hydrocarbon-bearing formation via a production wellborecomprises adding a concentration of a viscosity reducer to the fluid todegrade the polymer present in the fluid and adding a concentration of aneutralizer to the fluid to neutralize the viscosity reducer in thefluid. The addition of the concentration of the viscosity reducer is ina sufficient quantity to allow for complete chemical degradation of thepolymer prior to the addition of the concentration of the neutralizer inthe fluid such that excess viscosity reducer is present in the fluid.The addition of the concentration of the neutralizer is sufficientlyupstream of any surface fluid processing equipment to allow for completeneutralization of the excess viscosity reducer such that excessneutralizer is present in the fluid prior to the fluid reaching any ofthe surface fluid processing equipment.

One embodiment of a system of treating fluid comprising hydrocarbons,water, and polymer being produced from a hydrocarbon-bearing formationvia a production wellbore comprises a production wellbore for producingfluid comprising hydrocarbons, water, and polymer from ahydrocarbon-bearing formation. The embodiment of the system alsocomprises a first injection apparatus for adding a concentration of aviscosity reducer to the fluid to degrade the polymer present in thefluid. The embodiment of the system also comprises a second injectionapparatus for adding a concentration of a neutralizer to the fluid toneutralize the viscosity reducer in the fluid. The embodiment of thesystem also comprises surface fluid processing equipment for separatingthe hydrocarbons from the fluid. The addition of the concentration ofthe viscosity reducer is in a sufficient quantity to allow for completechemical degradation of the polymer prior to the addition of theconcentration of the neutralizer in the fluid such that excess viscosityreducer is present in the fluid. The addition of the concentration ofthe neutralizer is sufficiently upstream of any of the surface fluidprocessing equipment to allow for complete neutralization of the excessviscosity reducer such that excess neutralizer is present in the fluidprior to the fluid reaching any of the surface fluid processingequipment.

DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates one embodiment of a method of treating fluidcomprising hydrocarbons, water, and polymer being produced from ahydrocarbon-bearing formation via a production wellbore.

FIG. 2 illustrates one embodiment of a system of treating fluidcomprising hydrocarbons, water, and polymer being produced from ahydrocarbon-bearing formation via a production wellbore.

FIG. 3 illustrates a more detailed view of the system of FIG. 2,including the surface fluid processing equipment of FIG. 2.

FIG. 4 illustrates a modification to the system of FIG. 3.

FIG. 5 is a plot illustrating a viscosity reduction example.

FIG. 6 is a plot illustrating a viscosity reducer example.

FIG. 7 is a plot illustrating a neutralizer example.

FIG. 8 is a plot illustrating another viscosity reduction example.

FIG. 9 illustrates an example showing a reduction in oil in wateremulsions due to a viscosity reducer.

FIG. 10 illustrates an example showing absence of gelling due to aviscosity reducer.

FIGS. 11A, 11B, and 11C illustrate different views of apparatuses thatmay be used in a laboratory setting to determine a concentration ofviscosity reducer to add for complete chemical degradation of a polymer,a concentration of neutralizer to add for complete neutralization of allexcess viscosity reducer, or any combination thereof according to theinstant disclosure.

Reference will now be made in detail to various embodiments, where likereference numerals designate corresponding parts throughout the severalviews. In the following detailed description, numerous specific detailsare set forth in order to provide a thorough understanding of thepresent disclosure and the embodiments described herein. However,embodiments described herein may be practiced without these specificdetails. In other instances, well-known methods, procedures, components,and mechanical apparatuses have not been described in detail so as notto unnecessarily obscure aspects of the embodiments.

DETAILED DESCRIPTION

TERMINOLOGY: The following terms will be used throughout thespecification and will have the following meanings unless otherwiseindicated.

Hydrocarbon-bearing formation: Hydrocarbon exploration processes,hydrocarbon recovery processes, or any combination thereof may beperformed on a “hydrocarbon-bearing formation”. The hydrocarbon-bearingformation refers to practically any volume under a surface containinghydrocarbons therein. For example, the hydrocarbon-bearing formation maybe practically anything under a terrestrial surface (e.g., a landsurface), practically anything under a seafloor, etc. A water column maybe above the hydrocarbon-bearing formation, such as in marinehydrocarbon exploration, in marine hydrocarbon recovery, etc. Thehydrocarbon-bearing formation may be onshore. The hydrocarbon-bearingformation may be offshore with shallow water or deep water above thehydrocarbon-bearing formation. The hydrocarbon-bearing formation mayinclude faults, fractures, overburdens, underburdens, salts, salt welds,rocks, sands, sediments, pore space, etc. The hydrocarbon-bearingformation may include practically any geologic point(s) or volume(s) ofinterest (such as a survey area) in some embodiments.

The hydrocarbon-bearing formation includes hydrocarbons, such as liquidhydrocarbons (also known as oil or petroleum), gas hydrocarbons (e.g.,natural gas), solid hydrocarbons (e.g., asphaltenes or waxes), acombination of hydrocarbons (e.g., a combination of liquid hydrocarbons,gas hydrocarbons, and solid hydrocarbons), etc. Light crude oil, mediumoil, heavy crude oil, and extra heavy oil, as defined by the AmericanPetroleum Institute (API) gravity, are examples of hydrocarbons. Indeed,examples of hydrocarbons are many and may include oil, natural gas,kerogen, bitumen, clathrates (also referred to as hydrates), etc. Thehydrocarbons may be discovered by hydrocarbon exploration processes.

The hydrocarbon-bearing formation may also include at least onewellbore. For example, at least one wellbore may be drilled into thehydrocarbon-bearing formation in order to confirm the presence of thehydrocarbons. As another example, at least one wellbore may be drilledinto the hydrocarbon-bearing formation in order to recover (alsoreferred to as produce) the hydrocarbons. The hydrocarbons may berecovered from the entire hydrocarbon-bearing formation or from aportion of the hydrocarbon-bearing formation. For example, thehydrocarbon-bearing formation may be divided up into one or morehydrocarbon zones, and hydrocarbons may be recovered from each desiredhydrocarbon zone. One or more of hydrocarbon zones may even be shut-into increase hydrocarbon recovery from a hydrocarbon zone that is notshut-in.

The hydrocarbon-bearing formation, the hydrocarbons, or any combinationthereof may also include non-hydrocarbon items. For example, thenon-hydrocarbon items may include connate water, brine, tracers, itemsused in enhanced oil recovery or other hydrocarbon recovery processes,items from other treatments (e.g., gels used in conformance control),etc.

In short, each hydrocarbon-bearing formation may have a variety ofcharacteristics, such as petrophysical rock properties, reservoir fluidproperties, reservoir conditions, hydrocarbon properties, or anycombination thereof. For example, each hydrocarbon-bearing formation (oreven zone or portion of the hydrocarbon-bearing formation) may beassociated with one or more of: temperature, porosity, salinity,permeability, water composition, mineralogy, hydrocarbon type,hydrocarbon quantity, reservoir location, pressure, etc. Those ofordinary skill in the art will appreciate that the characteristics aremany, including, but not limited to: shale gas, shale oil, tight gas,tight oil, tight carbonate, carbonate, vuggy carbonate, unconventional(e.g., a rock matrix with an average pore size less than 1 micrometer),diatomite, geothermal, coalbed methane, hydrate, mineral, metal, ahydrocarbon-bearing formation having a permeability in the range of 0.01microdarcy to 10 millidarcy, a hydrocarbon-bearing formation having apermeability in the range of 10 millidarcy to 40,000 millidarcy, etc.

The term “hydrocarbon-bearing formation” may be used synonymously withthe term “reservoir” or “subsurface reservoir” or “subsurface region ofinterest” or “formation” or “subsurface formation” or “subsurface volumeof interest”. Thus, the terms “hydrocarbon-bearing formation,”“hydrocarbons,” and the like are not limited to any description orconfiguration described herein.

Wellbore: A wellbore refers to a single hole, usually cylindrical, thatis drilled into the hydrocarbon-bearing formation for hydrocarbonexploration, hydrocarbon recovery, surveillance, or any combinationthereof. The wellbore is surrounded by the hydrocarbon-bearing formationand the wellbore is in fluidic communication with thehydrocarbon-bearing formation (e.g., via perforations). The wellbore isalso in fluidic communication with the surface, such as a surfacefacility that may include oil/gas/water separators, gas compressors,storage tanks, pumps, gauges, sensors, meters, pipelines, etc.

The wellbore may be used for injection (referred to as an injectionwellbore) in some embodiments. The wellbore may be used for production(referred to as a production wellbore) in some embodiments. The wellboremay be used for a single function, such as only injection, in someembodiments. The wellbore may be used for a plurality of functions, suchas production then injection, in some embodiments. The use of thewellbore may also be changed, for example, a particular wellbore may beturned into an injection wellbore after a different previous use such asproduction. The wellbore may be drilled amongst existing wellbores, forexample, as an infill wellbore. A plurality of wellbores (e.g., tens tohundreds of wellbores) are often used in a field to recoverhydrocarbons. As an example, hydrocarbons may be swept from at least oneinjection wellbore towards at least one production wellbore and uptowards the surface for processing.

The wellbore may have straight, directional, or a combination oftrajectories. For example, the wellbore may be a vertical wellbore, ahorizontal wellbore, a multilateral wellbore, an inclined wellbore, aslanted wellbore, etc. The wellbore may include a change in deviation.As an example, the deviation is changing when the wellbore is curving.In a horizontal wellbore, the deviation is changing at the curvedsection (sometimes referred to as the heel) between the vertical sectionof the horizontal wellbore and the horizontal section of the horizontalwellbore.

The wellbore may include a plurality of components, such as, but notlimited to, a casing, a liner, a tubing string, a heating element, asensor, a packer, a screen, a gravel pack, etc. The “casing” refers to asteel pipe cemented in place during the wellbore construction process tostabilize the wellbore. The “liner” refers to any string of casing inwhich the top does not extend to the surface but instead is suspendedfrom inside the previous casing. The “tubing string” or simply “tubing”is made up of a plurality of tubulars (e.g., tubing, tubing joints, pupjoints, etc.) connected together. The tubing string is lowered into thecasing or the liner for injecting a fluid into the hydrocarbon-bearingformation, producing a fluid from the hydrocarbon-bearing formation, orany combination thereof. The casing may be cemented in place, with thecement positioned in the annulus between the hydrocarbon-bearingformation and the outside of the casing. The wellbore may also includeany completion hardware that is not discussed separately. If thewellbore is drilled offshore, the wellbore may include some of theprevious components plus other offshore components, such as a riser.

The wellbore may also include equipment to control fluid flow into thewellbore, control fluid flow out of the wellbore, or any combinationthereof. For example, each wellbore may include a wellhead, a BOP,chokes, valves, or other control devices. These control devices may belocated on the surface, under the surface (e.g., downhole in thewellbore), or any combination thereof. In some embodiments, the samecontrol devices may be used to control fluid flow into and out of thewellbore. In some embodiments, different control devices may be used tocontrol fluid flow into and out of the wellbore. In some embodiments,the rate of flow of fluids through the wellbore may depend on the fluidhandling capacities of the surface facility that is in fluidiccommunication with the wellbore. The control devices may also beutilized to control the pressure profile of the wellbore.

The equipment to be used in controlling fluid flow into and out of thewellbore may be dependent on the specifics of the wellbore, thehydrocarbon-bearing formation, the surface facility, etc. However, forsimplicity, the term “control apparatus” is meant to represent anywellhead(s), BOP(s), choke(s), valve(s), fluid(s), and other equipmentand techniques related to controlling fluid flow into and out of thewellbore.

The wellbore may be drilled into the hydrocarbon-bearing formation usingpractically any drilling technique and equipment known in the art, suchas geosteering, directional drilling, etc. Drilling the wellbore mayinclude using a tool, such as a drilling tool that includes a drill bitand a drill string. Drilling fluid, such as drilling mud, may be usedwhile drilling in order to cool the drill tool and remove cuttings.Other tools may also be used while drilling or after drilling, such asmeasurement-while-drilling (MWD) tools, seismic-while-drilling (SWD)tools, wireline tools, logging-while-drilling (LWD) tools, or otherdownhole tools. After drilling to a predetermined depth, the drillstring and the drill bit are removed, and then the casing, the tubing,etc. may be installed according to the design of the wellbore.

The equipment to be used in drilling the wellbore may be dependent onthe design of the wellbore, the hydrocarbon-bearing formation, thehydrocarbons, etc. However, for simplicity, the term “drillingapparatus” is meant to represent any drill bit(s), drill string(s),drilling fluid(s), and other equipment and techniques related todrilling the wellbore.

The term “wellbore” may be used synonymously with the terms “borehole,”“well,” or “well bore.” The term “wellbore” is not limited to anydescription or configuration described herein.

Hydrocarbon recovery: The hydrocarbons may be recovered (sometimesreferred to as produced) from the hydrocarbon-bearing formation usingprimary recovery (e.g., by relying on pressure to recover thehydrocarbons), secondary recovery (e.g., by using water injection (alsoreferred to as waterflooding) or natural gas injection to recoverhydrocarbons), enhanced oil recovery (EOR), or any combination thereof.Enhanced oil recovery or EOR refers to techniques for increasing theamount of hydrocarbons that may be extracted from thehydrocarbon-bearing formation. Enhanced oil recovery may also bereferred to as tertiary oil recovery. Secondary recovery is sometimesjust referred to as improved oil recovery or enhanced oil recovery.

EOR processes include, for example: (a) miscible gas injection (whichincludes, for example, carbon dioxide flooding), (b) chemical injection(sometimes referred to as chemical enhanced oil recovery (CEOR) thatincludes, for example, polymer flooding, alkaline flooding, surfactantflooding, conformance control, as well as combinations thereof such asalkaline-polymer flooding, surfactant-polymer flooding, oralkaline-surfactant-polymer flooding), (c) microbial injection, (d)thermal recovery (which includes, for example, cyclic steam and steamflooding), or any combination thereof.

Indeed, an EOR process may include practically any flooding involvingpolymer, a chemical agent, or any combination thereof. For example, theEOR process may comprise a polymer (P) flooding process, analkaline-polymer (AP) flooding process, a surfactant-polymer (SP)flooding process, an alkaline-surfactant-polymer (ASP) flooding process,or any combination thereof.

Turning to the EOR process, the polymer can be initially provided as apowder that is mixed on-site. Alternatively, the polymer can beinitially provided in a partial-strength solution, such as gel,emulsion, or liquid that is made up partly of polymer (e.g., 2%-60%polymer) in a solute such as water. An injection fluid may be mixedon-site to include the polymer, e.g., by mixing the polymer (that mayhave been initially provided as a powder, gel, emulsion, or liquid) witha solute such as water. Preparing the powder polymer may involve atleast one additional mixing step and storage of the result in a tank(e.g., tank on the surface). The result from the tank is then mixed withthe solute to form the injection fluid. The injection fluid may alsoinclude other components in addition to the polymer.

In one embodiment, an injection fluid may include a variety ofcomponents. For example, the injection fluid may include (i) a water oraqueous phase component, such as brine, a mixture of brine and gas, etc.The injection fluid may include (ii) a polymer component, and thepolymer component may even include various constituents such as water,mineral oil, one or more solvents, one or more optional additives, etc.The polymer component may include additional and/or alternativeconstituents as well. The injection fluid may include (iii) a thirdcomponent, such as one or more solvents, one or more optional additives,etc. The third component may include additional and/or alternativeconstituents as well. For example, the polymer component may includesurfactant and the third component may also include surfactant. Theinjection fluid may include additional components as well, for example,that may be mixed on-site. Thus, the injection fluid may include avariety of components, and the actual components of the injection fluidmay depend, for example, on the hydrocarbon-bearing formation and thehydrocarbons.

The injection fluid is injected into at least one injection wellborethrough the wellhead of each injection wellbore using at least one pump.The hydrocarbons will typically be swept from the injection wellboredrilled into the hydrocarbon-bearing formation through thehydrocarbon-bearing formation towards at least one production wellboredrilled into the hydrocarbon-bearing formation, enter the at least oneproduction wellbore, and flow up to the surface for processing.

The physical equipment to be used in preparing and injecting theinjection fluid may be dependent on the specifics of the injectionfluid, the specifics of the polymer, the specifics of the injectionwellbore(s), specifics of the production wellbore(s), the specifics ofthe hydrocarbon-bearing formation, etc. However, for simplicity, theterm “injection apparatus” is meant to represent any tank(s), mixer(s),pump(s), manifold(s), pipeline(s), valve(s), fluid(s), polymer(s),chemical agent(s), and other equipment and techniques related topreparing the injection fluid comprising the polymer and injecting theinjection fluid. The “injection apparatus” may even be utilized foranother injection in some embodiments.

Water: The term “water” may be practically any aqueous-based liquid thatmay be injected into the hydrocarbon-bearing formation. In someembodiments, the water may comprise brine (e.g., reservoir or syntheticbrine), sea water, brackish water, river water, lake or pond water,aquifer water, wastewater (e.g., reclaimed or recycled), flowback orproduced formation brine, fresh water, or any combination thereof. Watercan have any salt content. In some embodiments, brines may comprise, butare not necessarily limited to, heavy brines, monovalent brines,divalent brines, and trivalent brines that comprise soluble salts likesodium chloride, calcium chloride, calcium bromide, zinc bromide,potassium carbonate, sodium formate, potassium formate, cesium formate,sodium acetate, potassium acetate, calcium acetate, ammonium acetate,ammonium chloride, ammonium bromide, sodium nitrate, potassium nitrate,ammonium nitrate, ammonium sulfate, calcium nitrate, sodium carbonate,potassium carbonate, any derivative thereof, or any combination thereof.The term “water” may be used synonymously with the terms “brine” or“solute”. The term “water” is not limited to any description orconfiguration described herein.

Polymer: The term “polymer” refers to practically any polymer that maybe injected into and/or produced from the hydrocarbon-bearing formation.As indicated hereinabove, for example, the polymer may be initiallyprovided as a powder that is mixed on-site by at least one mixer.Examples of suitable powder polymers include biopolymers or syntheticpolymers. Examples of suitable powder polymers may also include anymixture of these powder polymers (including any modifications of thesepowder polymers). The “polymer” may even comprise a plurality ofpolymers in some embodiments. As indicated hereinabove, as anotherexample, the polymer may be initially provided in a partial-strengthsolution, such as gel, emulsion, or liquid that is made up partly ofpolymer in a solute such as water (e.g., brine). Depending on thespecific embodiment, the “polymer” may be a polymer composition, apolymer solution, a polymer suspension, polymer dispersion, a liquidpolymer, etc. Thus, the “polymer” itself may be made up of variousconstituents. The “polymer” itself may be made up of variousconstituents such as water, mineral oil, one or more solvents, one ormore optional additives, or any combination thereof. The polymercomponent may include additional and/or alternative constituents aswell.

As discussed hereinabove, the injection fluid can be mixed on-site toinclude the polymer, e.g., by mixing the polymer (may have beeninitially provided as a powder, gel, emulsion, or liquid), with a solutesuch as water. At least some of the polymer from the injection fluid maybecome a component of the fluid being produced from thehydrocarbon-bearing formation via the production wellbore regardless ofhow the polymer was initially provided, mixed, and injected. Forexample, polymer such as HPAMs and/or AMPS, discussed furtherhereinbelow, may be present in the fluid being produced from thehydrocarbon-bearing formation via the production wellbore regardless ofhow the HPAMs and/or AMPs was initially provided, mixed, and injected.

Turning to powder polymer, a powder polymer may be selected or tailoredaccording to the characteristics of the hydrocarbon-bearing formationfor the EOR process such as permeability, temperature, salinity, or anycombination thereof. Examples of suitable powder polymers includebiopolymers such as polysaccharides. Polysaccharides can be xanthan gum,scleroglucan, guar gum, schizophyllan, any derivative thereof (e.g.,such as a modified chain), or any combination thereof. Examples ofsuitable powder synthetic polymers include polyacrylamides, partiallyhydrolyzed polyacrylamides (HPAMs or PHPAs), hydrophobically-modifiedassociative polymers (APs), or any combination thereof. Also includedare co-polymers of polyacrylamide (PAM) and one or both of 2-acrylamido2-methylpropane sulfonic acid (and/or sodium salt) commonly referred toas AMPS (also more generally known as acrylamido tertiarybutyl sulfonicacid or ATBS), N-vinyl pyrrolidone (NVP), and the NVP-based syntheticmay be single-, co-, or ter-polymers. In one embodiment, the polymer isselected from the group of polyacrylamides, partially hydrolyzedpolyacrylamides, hydrophobically-modified associative polymers,copolymers of polyacrylamide and one or both of 2-acrylamido2-methylpropane sulfonic acid and salts thereof and N-vinyl pyrrolidone,single-, co-, or ter-polymers of N-vinyl pyrrolidones, polyacrylic acid,polyvinyl alcohol, and mixtures thereof. In one embodiment, the powdersynthetic polymer comprises polyacrylic acid (PAA). In one embodiment,the powder synthetic polymer comprises polyvinyl alcohol (PVA).Copolymers may be made of any combination or mixture above, for example,a combination of NVP and ATBS. Thus, examples of suitable powderpolymers include biopolymers or synthetic polymers. Examples of suitablepowder polymers can also include any mixture of these powder polymers(including any modifications of these powder polymers). Indeed, theterminology “mixtures thereof” or “combinations thereof” can eveninclude “modifications thereof” herein.

In one embodiment, the powder polymer is an anionic polyacrylamidehaving a charge ranging from 0 to about 40%, which may be a result ofthe reaction to form polyacrylamide that generally starts with about 0%to about 40% acrylic acid or acrylate salt. The polymer that may beformed with acrylic acid or an acid salt monomer is called anionicpolyacrylamide because the polymer itself contains a negative charge,which is balanced by a cation, usually sodium. A polymer made withlittle or no acid or acrylate salt is considered nonionic polyacrylamidebecause the polymer essentially contains no charge. The powder polymerhas an average molecular weights (Mw) of: 0.5 to 30 Million Daltons inone embodiment; from 1 to 15 Million Daltons in a second embodiment; atleast 2 Million Daltons in a third embodiment; from 4 to 25 MillionDaltons in a fourth embodiment; less than or equal to 25 Million Daltonsin a fifth embodiment; and at least 0.5 Million Daltons in a sixthembodiment.

In some embodiments, the polymer powders have an average particle sizeof at least 5 mesh in one embodiment, 10-100 mesh in a secondembodiment, and 40-400 mesh in a third embodiment. The polymer powderundergoes an additional milling, grinding, or crushing prior to mixingwith the water-soluble solvent in the preparation, for a particle sizeof 1-1000 μm in one embodiment; from 10-500 μm in a second embodiment;at least 5 μm in a third embodiment; and from 20-500 μm in a fourthembodiment.

Liquid polymers may be utilized in some embodiments. For example, aninverted polymer solution may be prepared by providing a liquid polymer(LP) composition comprising: one or more hydrophobic liquids having aboiling point at least 100° C.; at least 39% by weight of one or moresynthetic (co)polymers; one or more emulsifier surfactants; and one ormore inverting surfactants. Preparing the inverted polymer solution mayalso comprise inverting the LP composition in an aqueous fluid toprovide an inverted polymer solution having a concentration of synthetic(co)polymer of from 50 to 15,000 ppm. The inverted polymer solution hasa filter ratio of 1.5 or less at 15 psi using a 1.2 micron filter. Theinverted polymer solution may be used in an enhanced oil recovery (EOR)operation. The term operation may be used interchangeably with processor application as in EOR process or EOR application.

As another example, an inverted polymer solution may be prepared byproviding a liquid polymer (LP) composition in the form of an inverseemulsion comprising: one or more hydrophobic liquids having a boilingpoint at least 100° C.; up to 38% by weight of one or more synthetic(co)polymers; one or more emulsifier surfactants; and one or moreinverting surfactants. Preparing the inverted polymer solution may alsocomprise inverting the LP composition in an aqueous fluid to provide aninverted polymer solution having a concentration of synthetic(co)polymer of from 50 to 15,000 ppm. The inverted polymer solution hasa filter ratio of 1.5 or less at 15 psi using a 1.2 micron filter. Theinverted polymer solution may be used in an enhanced oil recovery (EOR)operation.

As another example, an inverted polymer solution may be prepared byproviding a liquid polymer (LP) composition in the form of an inverseemulsion comprising: one or more hydrophobic liquids having a boilingpoint at least 100° C.; up to 35% by weight of one or more synthetic(co)polymers; one or more emulsifier surfactants; and one or moreinverting surfactants. Preparing the inverted polymer solution may alsocomprise inverting the LP composition in an aqueous fluid to provide aninverted polymer solution having a concentration of synthetic(co)polymer of from 50 to 15,000 ppm. The inverted polymer solution hasa filter ratio of 1.5 or less at 15 psi using a 1.2 micron filter. Theinverted polymer solution may be used in an enhanced oil recovery (EOR)operation.

At least one stabilizer may also be utilized in the context of liquidpolymers in some embodiments. In one embodiment, the filter ratio of 1.5or less may comprise a filter ratio of 1 to 1.5. In one embodiment, thefilter ratio of 1.5 or less may comprise a filter ratio of 1 to 1.1. Inone embodiment, the filter ratio of 1.5 or less may comprise a filterratio of 1 to 1.2. In one embodiment, the filter ratio of 1.5 or lessmay comprise a filter ratio of 1 to 1.3. In one embodiment, the filterratio of 1.5 or less may comprise a filter ratio of 1 to 1.4. In oneembodiment, the filter ratio has a range of 1.1 to 1.3. In oneembodiment, the filter ratio of 1.5 or less may comprise a minimum of 1.In one embodiment, the filter ratio is 1.5 or less as well as morethan 1. The filter ratio can be determined using the 1.2 μm filter at 15psi (plus or minus 10% of 15 psi), for example, at ambient temperature(e.g., 25° C.). The 1.2 micron filter can have a diameter of 47 mm or 90mm, and the filter ratio can be calculated as the ratio of the time for180 to 200 ml of the injection fluid to filter divided by the time for60 to 80 ml of the injection fluid to filter:

${FR} = \frac{{{\,^{t}200}\mspace{11mu}{ml}} - {{\,^{t}180}\mspace{11mu}{ml}}}{{{\,^{t}80}\mspace{11mu}{ml}} - {{\,^{t}60}\mspace{11mu}{ml}}}$

One embodiment of recovering hydrocarbons using a liquid polymercomprises: (a) providing a subsurface reservoir containing hydrocarbonsthere within; (b) providing a wellbore in fluid communication with thesubsurface reservoir; (c) preparing an inverted polymer solution, suchas in any of the examples above; and (d) injecting the inverted polymersolution through the wellbore into the subsurface reservoir.

Discussions on polymers, polymer mixing, and the like may be found inthe following: U.S. Pat. No. 9,909,053 (Docket No. T-9845A), U.S. Pat.No. 9,896,617 (Docket No. T-9845B), U.S. Pat. No. 9,902,894 (Docket No.T-9845C), U.S. Pat. No. 9,902,895 (Docket No. T-9846), U.S. Patent App.Pub. No. 2018/0031462 (Docket No. T-10484), U.S. Ser. No. 15/996,040with U.S. Patent App. Pub. No. 2018-0275036 (Docket No. T-10484-C1),U.S. Patent App. Pub. No. 2017/0158947 (Docket No. T-10275A), Pub. No.WO2017100344 (Docket No. T-10275A), U.S. Patent App. Pub. No.2017/0158948 (Docket No. T-10275B), US Patent App. Pub. No. 2018/0155505(Docket No. T-10444), Pub. No. WO2018/106913 (Docket No. T-10444), U.S.Ser. No. 16/024,147 with U.S. Patent App. Pub. No. 2019/0002754 (DocketNo. T-10275F), App. No. PCT/US18/040401 with Pub. No. WO 2019/006369(Docket No. T-10275F), and Dwarakanath et al., “Permeability ReductionDue to use of Liquid Polymers and Development of Remediation Options,”SPE 179657, SPE IOR Symposium in Tulsa, 2016, each of which isincorporated by reference.

Solvent: The term “solvent” may refer to practically any solvent thatmay be injected into a hydrocarbon-bearing formation. The solvent may bea water-soluble solvent. The water soluble solvent may be selected fromone or more of surfactants (e.g., non-ionic surfactants), ethers (e.g.,glycol ethers), alcohols, co-solvents, or any combination thereof, foran HLB of greater than or equal to 8 (e.g., at least 8) as measured bymethods known in the art, e.g., NMR, gas-liquid chromatography, orinvert emulsion experiments using Griffin's method or Davies's method.In one embodiment, the HLB is about 10 to about 20. In anotherembodiment, the HLB is less than or equal to 15. Examples of suitablewater-soluble solvents can also include any mixture of thesewater-soluble solvents (including any modifications of these watersoluble solvents). For example, the water-soluble solvent can include amixture of non-ionic and anionic surfactants. The anionic surfactant canbe present in an amount of less than or equal to 5 wt. % as astabilizer.

Examples of suitable water-soluble solvents include, but are not limitedto, (a) alcohol ethoxylates (-EO-), (b) alcohol alkoxylates (-PO-EO-),(c) alkyl polyglycol ethers, (d) alkyl phenoxy ethoxylates, (e) anethylene glycol butyl ether (EGBE), (f) a diethylene glycol butyl ether(DGBE), (g) a triethylene glycol butyl ether (TEGBE), (h)polyoxyethylene nonylphenylether, branched, or (i) any combinationthereof. In one embodiment, the water-soluble solvent comprises analcohol, such as isopropyl alcohol (IPA), isobutyl alcohol (IBA),secondary butyl alcohol (SBA), or any combination thereof. In anotherembodiment, the water-soluble solvent comprises a low MW ether such asethylene glycol monobutyl ether.

In embodiments with the use of HPAM type synthetic polymers, a non-ionicsurfactant is used as the water-soluble solvent. In yet anotherembodiment, a mixture or combination of surfactants is used, e.g.,non-ionic surfactants and anionic surfactants in a weight ratio rangingfrom 6:1 to 2:1. Examples of non-ionic surfactants for use as thewater-soluble solvents comprise ethoxylated surfactants, nonylphenolethoxylates or alcohol ethoxylate, other ethoxylated surfactants, or anycombination thereof. In another embodiment, the anionic surfactantscomprise internal olefin sulfonates, isomerized olefin sulfonates, alkylaryl sulfonates, medium alcohol (C10 to C17) alkoxy sulfates, alcoholether [alkoxy]carboxylates, alcohol ether [alkoxy]sulfates, alkylsulfonate, alpha olefin sulfonates (AOS), sulfosuccinate (e.g., dihexylsulfosuccinate), or any combination thereof. In yet another embodiment,the water-soluble solvent comprises alkylpolyalkoxy sulfates asdisclosed in U.S. Pat. No. 8,853,136, sulfonated amphoteric surfactantsas disclosed in U.S. Pat. No. 8,714,247, surfactants based on anionicalkyl alkoxylates as disclosed in US Patent Publication No. 20140116689,or any combination thereof, each of which are incorporated herein byreference in its entirety.

In one embodiment, the water-soluble solvent comprises isopropyl alcohol(IPA), n-propyl alcohol, isobutyl alcohol (IBA), methyl-isobutylalcohol, secondary butyl alcohol (SBA), ethylene glycol monobutyl ether,diethylene glycol monobutyl ether, triethylene glycol monobutyl ether,or any combination thereof. In one embodiment, the water soluble solventcomprises an ionic surfactant selected from ethoxylated surfactants,nonylphenol ethoxylates, alcohol ethoxylates, internal olefinsulfonates, isomerized olefin sulfonates, alkyl aryl sulfonates, mediumalcohol (C10 to C17) alkoxy sulfates, alcohol ether[alkoxy]carboxylates, alcohol ether [alkoxy]sulfates, alkyl sulfonate,alpha olefin sulfonates (AOS), sulfosuccinates (e.g., dihexylsulfosuccinates), alkylpolyalkoxy sulfates, sulfonated amphotericsurfactants, or any combination thereof. Examples of suitablewater-soluble solvents can also include any combination or mixture ofthese water-soluble solvents (including any modifications of these watersoluble solvents).

In one embodiment, the water soluble solvent comprises a co-solvent, andthe co-solvent comprises ionic surfactant, non-ionic surfactant, anionicsurfactant, cationic surfactant, nonionic surfactant, amphotericsurfactant, ketones, esters, ethers, glycol ethers, glycol ether esters,lactams, cyclic urea, alcohols, aromatic hydrocarbons, aliphatichydrocarbons, alicyclic hydrocarbons, nitroalkanes, unsaturatedhydrocarbons, halocarbons, alkyl aryl sulfonates (AAS), alpha olefinsulfonates (AOS), internal olefin sulfonates (IOS), alcohol ethersulfates derived from propoxylated C12 to C20 alcohols, ethoxylatedalcohols, mixtures of an alcohol and an ethoxylated alcohol, mixtures ofanionic and cationic surfactants, disulfonated surfactants,polysulfonated surfactants, aromatic ether polysulfonates, isomerizedolefin sulfonates, alkyl aryl sulfonates, medium alcohol (C10 to C17)alkoxy sulfates, alcohol ether [alkoxy]carboxylates, alcohol ether[alkoxy] sulfates, primary amines, secondary amines, tertiary amines,quaternary ammonium cations, cationic surfactants that are linked to aterminal sulfonate or carboxylate group, alkyl aryl alkoxy alcohols,alkyl alkoxy alcohols, alkyl alkoxylated esters, alkyl polyglycosides,alkoxy ethoxyethanol compounds, isobutoxy ethoxyethanol (“iBDGE”),n-pentoxy ethoxyethanol (“n-PDGE”), 2-methylbutoxy ethoxyethanol(“2-MBDGE”), methylbutoxy ethoxyethanol (“3-MBDGE”), (3,3-dimethylbutoxyethoxyethanol (“3,3-DMBDGE”), cyclohexylmethyleneoxy ethoxyethanol(hereafter “CHMDGE”), 4-Methylpent-2-oxy ethoxyethanol (“MIBCDGE”),n-hexoxy ethoxyethanol (hereafter “n-HDGE”), 4-methylpentoxyethoxyethanol (“4-MPDGE”), butoxy ethanol, propoxy ethanol, hexoxyethanol, isoproproxy 2-propanol, butoxy 2-propanol, propoxy 2-propanol,tertiary butoxy 2-propanol, ethoxy ethanol, butoxy ethoxy ethanol,propoxy ethoxy ethanol, hexoxy ethoxy ethanol, methoxy ethanol, methoxy2-propanol and ethoxy ethanol, n-methyl-2-pyrrolidone, dimethyl ethyleneurea, or any combination thereof. Examples of suitable co-solvents canalso include any mixture of these co-solvents (including anymodifications of these co-solvents).

Optional additive: The term “optional additive” refers to practicallyany other additive that may be injected into the hydrocarbon-bearingformation. Examples of optional additives comprise anionic or non-ionicsurfactants, biocides, co-solvents, chelators, reducing agents/oxygenscavengers, stabilizers, etc., or any combination thereof, in an amountof less than or equal to 10 wt. % (of the total weight of the polymersuspension). In one embodiment, a stabilizer is added to furtherstabilize a suspended polymer. For example, an anionic surfactant can bepresent in an amount of less than or equal to 5 wt. % as a stabilizer.

Examples of internal olefin sulfonates and the methods to make them arefound in U.S. Pat. No. 5,488,148, U.S. Patent Application Publication2009/0112014, and SPE 129766, each of which is incorporated byreference. Examples of suitable surfactants are disclosed, for example,in U.S. Pat. Nos. 3,811,504, 3,811,505, 3,811,507, 3,890,239, 4,463,806,6,022,843, 6,225,267, 7,629,299, 7,770,641, 9,976,072, 8,211, 837,9,422,469, 9,605,198, 9,617,464, and 9,976,072; WIPO Patent ApplicationNos. WO 2008/079855, WO 2012/027757 and WO 2011/094442; as well as U.S.Patent Application Nos. 2005/0199395, 2006/0185845, 2006/0189486,2009/0270281, 2011/0046024, 2011/0100402, 2011/0190175, 2007/0191633,2010/004843. 2011/0201531, 2011/0190174, 2011/0071057, 2011/0059873,2011/0059872, 2011/0048721, 2010/0319920, 2010/0292110, and2017/0198202, each of which is hereby incorporated by reference hereinin its entirety for its description of example surfactants. U.S. Pat.No. 9,752,071 (Docket No. T-9353) and U.S. Pat. No. 10,011,757 (DocketNo. T-9353-C1) are also incorporated by reference.

Those of ordinary skill in the art will appreciate that these are notexhaustive lists of polymers, solvents, and optional additives. Theterms “polymer”, “solvent”, and “optional additive” are not limited toany description or configuration described herein.

Sulfur: The term “sulfur” is utilized herein to refer to practicallyanything that contains the element “S” such as sulfate (SO4-), sulfide(S—), and the like. As such, sulfur may include a sulfate, a sulfite, asulfide, a thiosulfate, a bisulfite, etc.

Viscosity reducer: The term “viscosity reducer” refers to practicallyany agent that reduces viscosity (e.g., thickness). A concentration ofthe viscosity reducer will be added to the fluid being produced from thehydrocarbon-bearing formation via the production wellbore (e.g., at afirst location) to degrade the polymer present in the fluid. Theaddition of the concentration of the viscosity reducer (e.g., at a firstlocation) is in a sufficient quantity to allow for complete chemicaldegradation of the polymer prior to the addition of the concentration ofthe neutralizer (e.g., at the second location) in the fluid such thatexcess viscosity reducer is present in the fluid. The addition of theconcentration of the neutralizer (e.g., at the second location) issufficiently upstream of any surface fluid processing equipment to allowfor complete neutralization of the excess viscosity reducer such thatexcess neutralizer is present in the fluid prior to the fluid reachingany of the surface fluid processing equipment. In one embodiment, thefirst location is sufficiently upstream of the second location to allowfor complete chemical degradation of the polymer prior to the fluidreaching the second location, and wherein the second location issufficiently upstream of any of the surface fluid processing equipmentto allow for complete neutralization of the excess viscosity reducer inthe fluid prior to the fluid reaching any of the surface fluidprocessing equipment.

As discussed further hereinbelow, the actual concentration of theviscosity reducer to be added in order for the polymer to undergocomplete chemical degradation may be determined in a laboratory settingusing a viscometer and using at least one hydrocarbon-free samplerepresentative with the fluid such as: (a) at least one sample of fluidbeing produced via the production wellbore, (b) at least one syntheticfluid sample representative with the fluid being produced, or anycombination thereof. Regarding synthetic fluid samples, ionchromatography may be utilized to determine the components present in abrine being produced, for example, and a synthetic brine sample withthose components may be created for the experiments. Hydrocarbons areomitted or separated from samples so that the hydrocarbons do not affectviscosity measurements.

It is worth noting that the concentration of the viscosity reducer thatis added may be higher than necessary for complete chemical degradationof the polymer in the fluid, sometimes referred to as “over chemicaldegradation”, to ensure that the polymer undergoes complete degradation.As such, this disclosure contemplates the following non-limitingscenarios: (i) scenario A where the concentration of the viscosityreducer determined in the laboratory setting that leads to completechemical degradation of the polymer (e.g., concentration X) is added, aswell as (ii) scenario B where more than the concentration of theviscosity reducer determined in the laboratory setting that leads tocomplete chemical degradation of the polymer (e.g., concentration X plusY equals concentration Z) is added (sometimes referred to as “overcomplete chemical degradation”). Both the concentration X and theconcentration Z may be determined in the laboratory setting. In bothscenarios, any excess viscosity reducer will be neutralized as discussedhereinbelow. For example, adding more than the necessary concentrationof the viscosity reducer determined in the laboratory setting ensuresthat the polymer will be completely chemically degraded in the fluidbeing produced even if the fluid being produced has a higher viscositydue to the hydrocarbons and other components in the fluid beingproduced. All of these scenarios are contemplated in this disclosure.

As discussed further hereinbelow, in some embodiment, complete chemicaldegradation of the polymer is accomplished when the viscosity of thefluid (e.g., water) returns to the viscosity of a polymer-free versionof that type of fluid (e.g., water), which may be determined using theviscometer. A viscosity of less than 1.4 cp with a minimum of 0.9 cpafter the addition of the viscosity reducer indicates that completechemical degradation of the polymer has been accomplished. A viscosityof less than 1.4 cp with a minimum of 0.9 cp (in some embodiments, theminimum is 1.0 cp) after the addition of the viscosity reducer alsoindicates the return of the viscosity to that of polymer-free fluid(e.g., water). In some embodiments, titration may be utilized todetermine whether complete chemical degradation of the polymer has beenaccomplished. In some embodiments, gel permeation chromatography (GPC)may be utilized to determine whether complete chemical degradation ofthe polymer has been accomplished.

In one embodiment, the viscosity reducer is a non-sulfur containingviscosity reducer. In one embodiment, the non-sulfur containingviscosity reducer comprises sodium hypochlorite. In one embodiment, thenon-sulfur containing viscosity reducer comprises sodium chlorite. Inone embodiment, the non-sulfur containing viscosity reducer compriseshydrogen peroxide. In one embodiment, the non-sulfur containingviscosity reducer comprises Fenton's reagent. In one embodiment, thenon-sulfur containing viscosity reducer comprises potassiumpermanganate. In one embodiment, the non-sulfur containing viscosityreducer comprises fluorine. In one embodiment, the non-sulfur containingviscosity reducer comprises hydroxyl radical. In one embodiment, thenon-sulfur containing viscosity reducer comprises atomic oxygen. In oneembodiment, the non-sulfur containing viscosity reducer comprises ozone.In one embodiment, the non-sulfur containing viscosity reducer comprisesperhydroxyl radical. In one embodiment, the non-sulfur containingviscosity reducer comprises hypobromous acid. In one embodiment, thenon-sulfur containing viscosity reducer comprises chlorine dioxide. Inone embodiment, the non-sulfur containing viscosity reducer compriseshypochlorous acid. In one embodiment, the non-sulfur containingviscosity reducer comprises hypoiodous acid. In one embodiment, thenon-sulfur containing viscosity reducer comprises chlorine. In oneembodiment, the non-sulfur containing viscosity reducer comprisesbromine. In one embodiment, the non-sulfur containing viscosity reducercomprises iodine. In one embodiment, the non-sulfur containing viscosityreducer comprises some other oxidizer. In one embodiment, the non-sulfurcontaining viscosity reducer comprises sodium hypochlorite, sodiumchlorite, hydrogen peroxide, Fenton's reagent, potassium permanganate,fluorine, hydroxyl radical, atomic oxygen, ozone, perhydroxyl radical,hypobromous acid, chlorine dioxide, hypochlorous acid, hypoiodous acid,chlorine, bromine, iodine, or any combination thereof. A person ofordinary skill in the art will appreciate that the non-sulfur containingviscosity reducer may be injected or added in solution form. Forexample, a solution may be prepared that comprises at least onenon-sulfur containing viscosity reducer, such as a solution thatincludes 15% active non-sulfur containing viscosity reducer and 85%water.

In one embodiment, the viscosity reducer comprises sodium hypochlorite.In one embodiment, the viscosity reducer comprises sodium chlorite. Inone embodiment, the viscosity reducer comprises hydrogen peroxide. Inone embodiment, the viscosity reducer comprises Fenton's reagent. In oneembodiment, the viscosity reducer comprises potassium permanganate. Inone embodiment, the viscosity reducer comprises fluorine. In oneembodiment, the viscosity reducer comprises hydroxyl radical. In oneembodiment, the viscosity reducer comprises atomic oxygen. In oneembodiment, the viscosity reducer comprises ozone. In one embodiment,the viscosity reducer comprises perhydroxyl radical. In one embodiment,the viscosity reducer comprises hypobromous acid. In one embodiment, theviscosity reducer comprises chlorine dioxide. In one embodiment, theviscosity reducer comprises hypochlorous acid. In one embodiment, theviscosity reducer comprises hypoiodous acid. In one embodiment, theviscosity reducer comprises chlorine. In one embodiment, the viscosityreducer comprises bromine. In one embodiment, the viscosity reducercomprises iodine. In one embodiment, the viscosity reducer comprisessome other oxidizer. In one embodiment, the viscosity reducer comprisestetrakis(hyroxymethyl)-phosphonium sulfate (THPS). THPS is sometimesutilized as a biocide. In one embodiment, the viscosity reducercomprises a biocide. In one embodiment, the viscosity reducer comprisessodium persulfate. In one embodiment, the viscosity reducer comprisessodium hypochlorite, sodium chlorite, hydrogen peroxide, Fenton'sreagent, potassium permanganate, fluorine, hydroxyl radical, atomicoxygen, ozone, perhydroxyl radical, hypobromous acid, chlorine dioxide,hypochlorous acid, hypoiodous acid, chlorine, bromine, iodine,tetrakis(hyroxymethyl)-phosphonium sulfate, a biocide, sodiumpersulfate, or any combination thereof. A person of ordinary skill inthe art will appreciate that the viscosity reducer may be injected oradded in solution form. For example, a solution may be prepared thatcomprises at least one viscosity reducer, such as a solution thatincludes 15% active viscosity reducer and 85% water.

In one embodiment, the viscosity reducer is added in a ratio of thepolymer to the viscosity reducer of 1:1 to 5:1 by concentration. In oneembodiment, the viscosity reducer is added in a ratio of the polymer tothe viscosity reducer of 1:1 to 4:1 by concentration. In one embodiment,the viscosity reducer is added in a ratio of the polymer to theviscosity reducer of 1:1 to 3:1 by concentration. In one embodiment, theviscosity reducer is added in a ratio of the polymer to the viscosityreducer of 1:1 to 2:1 by concentration. The concentration of theviscosity reducer ranges from any of the minimum values described aboveto any of the maximum values described above. In one embodiment, theviscosity reducer is added in a ratio of the polymer to the viscosityreducer of 1:1, 2:1, 3:1, 4:1, or 5:1 by concentration.

In one embodiment, the viscosity reducer is added in a concentration of1,500 ppm or less (e.g., 1400 ppm or less, 1300 ppm or less, 1200 ppm orless, 1100 ppm or less, 1000 ppm or less, 900 ppm or less, 800 ppm orless, 700 ppm or less, 600 ppm or less, 500 ppm or less, 400 ppm orless, 300 ppm or less, 200 ppm or less, 100 ppm or less, 90 ppm or less,80 ppm or less, 75 ppm or less, 70 ppm or less, 60 ppm or less, 50 ppmor less, 40 ppm or less, 30 ppm or less, 25 ppm or less, or 20 ppm orless). In one embodiment, the viscosity reducer is added in aconcentration of at least 10 ppm (e.g., at least 20 ppm, at least 25ppm, at least 30 ppm, at least 40 ppm, at least 50 ppm, at least 60 ppm,at least 70 ppm, at least 75 ppm, at least 80 ppm, at least 90 ppm, atleast 100 ppm, at least 200 ppm, at least 300 ppm, at least 400 ppm, atleast 500 ppm, at least 600 ppm, at least 700 ppm, at least 800 ppm, atleast 900 ppm, at least 1000 ppm, at least 1100 ppm, at least 1200 ppm,at least 1300 ppm, or at least 1400 ppm). In one embodiment, theviscosity reducer is added in a concentration of 10 ppm to 1500 ppm, 10ppm to 25 ppm, 10 ppm to 50 ppm, 10 ppm to 75 ppm, 10 ppm to 100 ppm, 10ppm to 500 ppm, 10 ppm to 1,000 ppm, 10 ppm to 1,300 ppm, 25 ppm to 75ppm, 25 ppm to 100 ppm, 25 ppm to 150 ppm, 25 ppm to 200 ppm, 25 ppm to500 ppm, or 25 ppm to 1,000 ppm. The concentration of the viscosityreducer ranges from any of the minimum values described above to any ofthe maximum values described above. The concentration of the viscosityreducer that is added may depend on the specifics of the viscosityreducer, depend on the specifics of the polymer, and how much of theviscosity reducer will result in complete chemical degradation of thepolymer, etc.

In one embodiment, residence time of the viscosity reducer in the fluidfor complete chemical degradation of the polymer is 10 minutes or less(e.g., 9 minutes or less, 8 minutes or less, 7 minutes or less, 6minutes or less, 5 minutes or less, 4 minutes or less, 3 minutes orless, 2 minutes or less, 1 minute or less, 55 seconds or less, 50seconds or less, 45 seconds or less, 40 seconds or less, 35 seconds orless, 30 seconds or less, 25 seconds or less, 20 seconds or less, or 15seconds or less). In one embodiment, residence time of the viscosityreducer in the fluid for complete chemical degradation of the polymer isat least 10 seconds (e.g., at least 15 seconds, at least 20 seconds, atleast 25 seconds, at least 30 seconds, at least 35 seconds, at least 40seconds, at least 45 seconds, at least 50 seconds, at least 55 seconds,at least 1 minute, at least 2 minutes, at least 3 minutes, at least 4minutes, at least 5 minutes, at least 6 minutes, at least 7 minutes, atleast 8 minutes, or at least 9 minutes). In one embodiment, residencetime of the viscosity reducer in the fluid for complete chemicaldegradation of the polymer is 10 seconds to 10 minutes, 10 seconds to 25seconds, 10 seconds to 45 seconds, 10 seconds to 1 minute, 10 seconds to2 minutes, 10 seconds to 5 minutes, or 10 seconds to 7 minutes. Theresidence time of the viscosity reducer in the fluid for completechemical degradation of the polymer ranges from any of the minimumvalues described above to any of the maximum values described above. Theresidence time of the viscosity reducer for complete chemicaldegradation of the polymer may depend on the specifics of the viscosityreducer, the specifics of the polymer, and how much time is needed forcomplete chemical degradation of that polymer with that viscosityreducer. The term “viscosity reducer” is not limited to any descriptionor configuration described herein.

Neutralizer: The term “neutralizer” refers to any agent that neutralizesthe viscosity reducer. A concentration of the neutralizer will be addedto the fluid (e.g., at a second location) to neutralize the viscosityreducer in the fluid. The addition of the concentration of the viscosityreducer (e.g., at a first location) is in a sufficient quantity to allowfor complete chemical degradation of the polymer prior to the additionof the concentration of the neutralizer (e.g., at the second location)in the fluid such that excess viscosity reducer is present in the fluid.The addition of the concentration of the neutralizer (e.g., at thesecond location) is sufficiently upstream of any surface fluidprocessing equipment to allow for complete neutralization of the excessviscosity reducer such that excess neutralizer is present in the fluidprior to the fluid reaching any of the surface fluid processingequipment.

As discussed further hereinbelow, the actual concentration of theneutralizer to be added in order for complete neutralization of allexcess viscosity reducer may be determined in the laboratory usingtitration and using at least one hydrocarbon-free sample representativewith the fluid such as: (a) at least one sample of fluid being producedvia the production wellbore, (b) at least one synthetic fluid samplerepresentative with the fluid being produced, or any combinationthereof. Regarding synthetic fluid samples, ion chromatography may beutilized to determine the components present in a brine being produced,for example, and a synthetic brine sample with those components may becreated for the experiments. Hydrocarbons may be omitted or separatedfrom samples so that the hydrocarbons do not affect viscositymeasurements. In some embodiments, the sample(s) utilized with theviscosity reducer experiments may even be utilized for the neutralizerexperiments.

It is worth noting that the concentration of the neutralizer that isadded may be higher than necessary for complete neutralization of allexcess viscosity reducer in the fluid, sometimes referred to as “overneutralization”, to ensure that the excess viscosity reducer iscompletely neutralized. As such, this disclosure contemplates thefollowing non-limiting scenarios: (i) scenario A where the concentrationof the neutralizer determined in the laboratory setting that leads tocomplete neutralization of the excess viscosity reducer (e.g.,concentration X1) is added, as well as (ii) scenario B where more thanthe concentration of the neutralizer determined in the laboratorysetting that leads to complete neutralization of the excess viscosityreducer (e.g., concentration X1 plus Y1 equals concentration Z1) isadded (sometimes referred to as “over neutralization”). Both theconcentration X1 and the concentration Z1 may be determined in thelaboratory setting. For example, adding more than the necessaryconcentration of the neutralizer determined in the laboratory settingensures that the excess viscosity reducer will be completely neutralizedin the fluid being produced even if the fluid being produced hashydrocarbons and other components in the fluid being produced. All ofthese scenarios are contemplated in this disclosure.

As discussed further hereinbelow, complete neutralization of all excessviscosity reducer is accomplished when excess (or residual) neutralizeris present in the sample, which may be determined using titration. Theexcess (or residual) neutralizer is present in the sample because theexcess viscosity reducer has been neutralized and there is no moreviscosity reducer to react with the neutralizer.

In one embodiment, the neutralizer is a non-sulfur containingneutralizer. In one embodiment, the non-sulfur containing neutralizercomprises ascorbic acid. In one embodiment, the non-sulfur containingneutralizer comprises sodium ascorbate. In one embodiment, thenon-sulfur containing neutralizer comprises citric acid. In oneembodiment, the non-sulfur containing neutralizer comprises ascorbicacid, sodium ascorbate, citric acid, or any combination thereof. Aperson of ordinary skill in the art will appreciate that the non-sulfurcontaining neutralizer may be injected or added in solution form.

In one embodiment, the neutralizer comprises ascorbic acid. In oneembodiment, the neutralizer comprises sodium ascorbate. In oneembodiment, the neutralizer comprises citric acid. In one embodiment,the neutralizer comprises sodium thiosulfate. In one embodiment, theneutralizer comprises sodium metabisulfite. In one embodiment, theneutralizer comprises ascorbic acid, sodium ascorbate, citric acid,sodium thiosulfate, sodium metabisulfite, or any combination thereof. Aperson of ordinary skill in the art will appreciate that the neutralizermay be injected or added in solution form.

In one embodiment, the neutralizer is added in a ratio of the excessviscosity reducer to the neutralizer of 1:2.5 to 1:5 by concentration.In one embodiment, the neutralizer is added in a ratio of the excessviscosity reducer to the neutralizer of 1:3 to 1:5 by concentration. Inone embodiment, the neutralizer is added in a ratio of the excessviscosity reducer to the neutralizer of 1:3.5 to 1:5 by concentration.In one embodiment, the neutralizer is added in a ratio of the excessviscosity reducer to the neutralizer of 1:4 to 1:5 by concentration. Inone embodiment, the neutralizer is added in a ratio of the excessviscosity reducer to the neutralizer of 1:4.5 to 1:5 by concentration.The concentration of the neutralizer ranges from any of the minimumvalues described above to any of the maximum values described above. Inone embodiment, the neutralizer is added in a ratio of the excessviscosity reducer to the neutralizer of 1:2.5, 1:3, 1:3.5, 1:4, 1:4.5,or 1:5 by concentration.

In one embodiment, the neutralizer is added in a concentration of 7,500ppm or less (e.g., 7,000 ppm or less, 6,500 ppm or less, 6,000 ppm orless, 5,500 ppm or less, 5,000 ppm or less, 4,500 ppm or less, 4,000 ppmor less, 3,500 ppm or less, 3,000 ppm or less, 2,500 ppm or less, 2,000ppm or less, 1,500 ppm or less, 1,000 ppm or less, 900 ppm or less, 800ppm or less, 700 ppm or less, 600 ppm or less, 500 ppm or less, 450 ppmor less, 400 ppm or less, 375 ppm or less, 350 ppm or less, 300 ppm orless, 250 ppm or less, 200 ppm or less, 150 ppm or less, 125 ppm orless, 100 ppm or less, 90 ppm or less, 80 ppm or less, 75 ppm or less,70 ppm or less, 60 ppm or less, 50 ppm or less, 40 ppm or less, or 30ppm or less). In one embodiment, the neutralizer is added in aconcentration of at least 25 ppm (e.g., at least 30 ppm, at least 40ppm, at least 50 ppm, at least 60 ppm, at least 70 ppm, at least 75 ppm,at least 80 ppm, at least 90 ppm, at least 100 ppm, at least 125 ppm, atleast 150 ppm, at least 200 ppm, at least 250 ppm, at least 300 ppm, atleast 350 ppm, at least 375 ppm, at least 400 ppm, at least 450 ppm, atleast 500 ppm, at least 600 ppm, at least 700 ppm, at least 800 ppm, atleast 900 ppm, at least 1,000 ppm, at least 1,500 ppm, at least 2,000ppm, at least 2,500 ppm, at least 3,000 ppm, at least 3,500 ppm, atleast 4,000 ppm, at least 4,500 ppm, at least 5,000 ppm, at least 5,500ppm, at least 6,000 ppm, at least 6,500 ppm, or at least 7,000 ppm). Inone embodiment, the neutralizer is added in a concentration of 25 ppm to7,500 ppm, 25 ppm to 35 ppm, 25 ppm to 50 ppm, 25 ppm to 75 ppm, 25 ppmto 100 ppm, 25 ppm to 125 ppm, 25 ppm to 250 ppm, 25 ppm to 375 ppm, 25ppm to 500 ppm, 25 ppm to 1,000 ppm, 25 ppm to 1,300 ppm, 25 ppm to1,500 ppm, 25 ppm to 2,000 ppm, 25 ppm to 2,500 ppm, 25 ppm to 3,000ppm, 25 ppm to 3,500 ppm, 25 ppm to 4,000 ppm, 25 ppm to 4,500 ppm, 25ppm to 5,000 ppm, 25 ppm to 5,500 ppm, 25 ppm to 6,000 ppm, 25 ppm to6,500 ppm, or 25 ppm to 7,000 ppm, The concentration of the neutralizerranges from any of the minimum values described above to any of themaximum values described above. The concentration of the neutralizerthat is added may depend on the specifics of the neutralizer, depend onthe specifics of the viscosity reducer, how much of the neutralizer willresult in complete neutralization of all excess viscosity reducer, etc.

In one embodiment, residence time of the neutralizer in the fluid forcomplete neutralization of all excess viscosity reducer in the fluid is10 minutes or less (e.g., 9 minutes or less, 8 minutes or less, 7minutes or less, 6 minutes or less, 5 minutes or less, 4 minutes orless, 3 minutes or less, 2 minutes or less, 1 minute or less, 90 secondsor less, 55 seconds or less, 50 seconds or less, 45 seconds or less, 40seconds or less, 35 seconds or less, 30 seconds or less, 25 seconds orless, 20 seconds or less, 15 seconds or less, 10 seconds or less, or 5seconds or less). In one embodiment, residence time of the neutralizerin the fluid for complete neutralization of all excess viscosity reducerin the fluid is at least 1 second (e.g., at least 5 seconds, at least 10seconds, at least 15 seconds, at least 20 seconds, at least 25 seconds,at least 30 seconds, at least 35 seconds, at least 40 seconds, at least45 seconds, at least 50 seconds, at least 55 seconds, at least 90seconds, at least 1 minute, at least 2 minutes, at least 3 minutes, atleast 4 minutes, at least 5 minutes, at least 6 minutes, at least 7minutes, at least 8 minutes, or at least 9 minutes). In one embodiment,residence time of the neutralizer in the fluid for completeneutralization of all excess viscosity reducer in the fluid is 1 secondto 10 minutes, 1 second to 10 seconds, 1 second to 20 seconds, 1 secondto 30 seconds, 1 second to 40 seconds, 1 second to 50 seconds, 1 secondto 60 seconds, 1 second to 70 seconds, 1 second to 80 seconds, 1 secondto 90 seconds, 1 second to 100 seconds, 1 second to 2 minutes, 1 secondto 3 minutes, 1 second to 4 minutes, 1 second to 5 minutes, 1 second to6 minutes, 1 second to 7 minutes, 1 second to 8 minutes, 1 second to 9minutes. The residence time of the neutralizer in the fluid for completeneutralization of all excess viscosity reducer in the fluid ranges fromany of the minimum values described above to any of the maximum valuesdescribed above. The term “neutralizer” is not limited to anydescription or configuration described herein.

Surface fluid processing equipment: Surface fluid processing equipmentmay include practically any equipment on the surface for processingfluid from the production wellbore. Processing may include separatingthe fluid, such as separating hydrocarbons (e.g., oil) and water in thefluid. Processing may include heating the fluid.

In one embodiment, the surface fluid processing equipment comprises afree water knockout (FWKO). In one embodiment, the surface fluidprocessing equipment comprises a heat exchanger (HX). In one embodiment,the surface fluid processing equipment comprises a separator. In oneembodiment, the surface fluid processing equipment comprises a flotationcell (e.g., flotation cell(s) such as a “WEMCO flotation cell” or “WEMCOflotation cells” such as, but not limited to, those commerciallyavailable under the trade name WEMCO™ for example from FLSmidth A/S). Inone embodiment, the surface fluid processing equipment comprises aninduced gas flotation (IFG) apparatus. In one embodiment, the surfacefluid processing equipment comprises a hydrocyclone. In one embodiment,the surface fluid processing equipment comprises a filter. In oneembodiment, the surface fluid processing equipment comprises a FWKO, aHX, a separator, a flotation cell, an IFG apparatus, a hydrocyclone, afilter, or any combination thereof. The term “surface fluid processingequipment” is not limited to any description or configuration describedherein.

Downhole fluid lifting equipment: Downhole fluid lifting equipment mayinclude practically any downhole equipment in the production wellborefor lifting fluid up to the surface. In one embodiment, the downholefluid lifting equipment comprises an electrical submersible pump (ESP).In one embodiment, the downhole fluid lifting equipment comprise ahydraulic submersible pump. In one embodiment, the downhole fluidlifting equipment comprises gas lift equipment (e.g., valves, mandrels).In one embodiment, the downhole fluid lifting equipment comprises anESP, a hydraulic submersible pump, gas lift equipment, or anycombination thereof. The term “downhole fluid lifting equipment” is notlimited to any description or configuration described herein.

Ambient temperature: Ambient temperature may depend on the exact placethat the temperature is measured. In some places, amendment temperatureis 5° C.-20° C. In some places, ambient temperature is 20° C.-25° C. Insome places, ambient temperature is 15° C.-25° C.

Other definitions: The term “proximate” is defined as “near”. If item Ais proximate to item B, then item A is near item B. For example, in someembodiments, item A may be in contact with item B. For example, in someembodiments, there may be at least one barrier between item A and item Bsuch that item A and item B are near each other, but not in contact witheach other. The barrier may be a fluid barrier, a non-fluid barrier(e.g., a structural barrier), or any combination thereof. Both scenariosare contemplated within the meaning of the term “proximate.”

The terms “comprise” (as well as forms, derivatives, or variationsthereof, such as “comprising” and “comprises”) and “include” (as well asforms, derivatives, or variations thereof, such as “including” and“includes”) are inclusive (i.e., open-ended) and do not excludeadditional elements or steps. For example, the terms “comprises” and/or“comprising,” when used in this specification, specify the presence ofstated features, integers, steps, operations, elements, and/orcomponents, but do not preclude the presence or addition of one or moreother features, integers, steps, operations, elements, components,and/or groups thereof. Accordingly, these terms are intended to not onlycover the recited element(s) or step(s), but may also include otherelements or steps not expressly recited. Furthermore, as used herein,the use of the terms “a” or “an” when used in conjunction with anelement may mean “one,” but it is also consistent with the meaning of“one or more,” “at least one,” and “one or more than one.” Therefore, anelement preceded by “a” or “an” does not, without more constraints,preclude the existence of additional identical elements.

The use of the term “about” applies to all numeric values, whether ornot explicitly indicated. This term generally refers to a range ofnumbers that one of ordinary skill in the art would consider as areasonable amount of deviation to the recited numeric values (i.e.,having the equivalent function or result). For example, this term can beconstrued as including a deviation of ±10 percent of the given numericvalue provided such a deviation does not alter the end function orresult of the value. Therefore, a value of about 1% can be construed tobe a range from 0.9% to 1.1%. Furthermore, a range may be construed toinclude the start and the end of the range. For example, a range of 10%to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, andincludes percentages in between 10% and 20%, unless explicitly statedotherwise herein.

The term “if” may be construed to mean “when” or “upon” or “in responseto determining” or “in accordance with a determination” or “in responseto detecting,” that a stated condition precedent is true, depending onthe context. Similarly, the phrase “if it is determined [that a statedcondition precedent is true]” or “if [a stated condition precedent istrue]” or “when [a stated condition precedent is true]” may be construedto mean “upon determining” or “in response to determining” or “inaccordance with a determination” or “upon detecting” or “in response todetecting” that the stated condition precedent is true, depending on thecontext.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in acomposition, or combinations of steps in a method), that while specificreference of each of the various individual and collective combinationsand permutations of these elements may not be explicitly disclosed, eachis specifically contemplated and described herein. By way of example, ifan item is described herein as including a component of type A, acomponent of type B, a component of type C, or any combination thereof,it is understood that this phrase describes all of the variousindividual and collective combinations and permutations of thesecomponents. For example, in some embodiments, the item described by thisphrase could include only a component of type A. In some embodiments,the item described by this phrase could include only a component of typeB. In some embodiments, the item described by this phrase could includeonly a component of type C. In some embodiments, the item described bythis phrase could include a component of type A and a component of typeB. In some embodiments, the item described by this phrase could includea component of type A and a component of type C. In some embodiments,the item described by this phrase could include a component of type Band a component of type C. In some embodiments, the item described bythis phrase could include a component of type A, a component of type B,and a component of type C. In some embodiments, the item described bythis phrase could include two or more components of type A (e.g., A1 andA2). In some embodiments, the item described by this phrase couldinclude two or more components of type B (e.g., B1 and B2). In someembodiments, the item described by this phrase could include two or morecomponents of type C (e.g., C1 and C2). In some embodiments, the itemdescribed by this phrase could include two or more of a first component(e.g., two or more components of type A (A1 and A2)), optionally one ormore of a second component (e.g., optionally one or more components oftype B), and optionally one or more of a third component (e.g.,optionally one or more components of type C). In some embodiments, theitem described by this phrase could include two or more of a firstcomponent (e.g., two or more components of type B (B1 and B2)),optionally one or more of a second component (e.g., optionally one ormore components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the item described by this phrase could include two or moreof a first component (e.g., two or more components of type C (C1 andC2)), optionally one or more of a second component (e.g., optionally oneor more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type B).

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to make and use the invention. The patentable scope is defined bythe claims, and may include other examples that occur to those skilledin the art. Such other examples are intended to be within the scope ofthe claims if they have elements that do not differ from the literallanguage of the claims, or if they include equivalent elements withinsubstantial differences from the literal languages of the claims.Unless defined otherwise, all technical and scientific terms used hereinhave the same meanings as commonly understood by one of skill in the artto which the disclosed invention belongs. All citations referred hereinare expressly incorporated by reference.

OVERVIEW: As discussed in the background, polymer is utilized inhydrocarbon recovery, but the polymer may also negatively affect theequipment utilized in hydrocarbon recovery. For example, polymer mayform scaling-gel that coats an ESP and impairs its cooling. Viscouspolymer may also interfere with effective oil water separation (Stoke'slaw) in the FWKO. Likewise, the oil separation in an IGF may also benegatively affected by higher water viscosity (Stoke's law). Even a lowconcentration of polymer may act as a drag-reducing agent (DRA) in ahydrocyclone and reduce its efficiency. Polymer also aggregates oildroplets and may plug a filter (e.g., filter membrane). Fresh ormechanically sheared polymer may also precipitate as a calcium scale onhot metal surfaces (80° C.-120° C.) in a HX, and the polymer-calcium-oilgel that forms has to be removed in order to restore the HX'sefficiency.

Furthermore, after free oil separation, up to a few hundred ppm of oilmay remain in the water. The presence of the polymer increases waterviscosity and traps or suspends more oil in the water, therebyincreasing the oil content. Historical techniques use heat, flocculants,and reverse emulsion breakers to remove oil from the water. All thesetechniques help with separation, but typically do not address the reasonfor increased trapping, and the reason is higher water viscosity due tothe polymer.

Embodiments of treating fluid comprising hydrocarbons, water, andpolymer being produced from a hydrocarbon-bearing formation via aproduction wellbore are provided herein. One embodiment of a method oftreating fluid comprising hydrocarbons, water, and polymer beingproduced from a hydrocarbon-bearing formation via a production wellborecomprises adding a concentration of a viscosity reducer to the fluid todegrade the polymer present in the fluid and adding a concentration of aneutralizer to the fluid to neutralize the viscosity reducer in thefluid. The addition of the concentration of the viscosity reducer is ina sufficient quantity to allow for complete chemical degradation of thepolymer prior to the addition of the concentration of the neutralizer inthe fluid such that excess viscosity reducer is present in the fluid.The addition of the concentration of the neutralizer is sufficientlyupstream of any surface fluid processing equipment to allow for completeneutralization of the excess viscosity reducer such that excessneutralizer is present in the fluid prior to the fluid reaching any ofthe surface fluid processing equipment. Residual or excess neutralizermay remain in the fluid as it reaches any fluid processing equipment.

Advantageously, those of ordinary skill in the art will appreciate thatthe polymer may be utilized for hydrocarbon recovery such as in EORprocesses (including CEOR processes), and the polymer in the fluid beingproduced via the production wellbore will undergo complete chemicaldegradation to reduce or eliminate negative impacts of the polymer onthe performance and life-span of surface fluid processing equipment.Depending on the embodiment, the complete chemical degradation of thepolymer will also reduce or eliminate negative impacts of the polymer onthe performance and life-span of downhole fluid lifting equipment. As anexample, the tendency of the polymer to precipitate in the presence ofdivalent ions and form polymer scale in the ESP and the HX may bereduced or even eliminated due to the complete chemical degradation ofthe polymer. As another example, the viscous impact of the polymer inthe FWKO, its drag reducing impact in the hydrocyclone, the viscousimpact to the separation of the oil droplets in the IGF, the rapidpolymer-oil-fouling of the filter (e.g., membrane filter), the foulingof the HX by polymer-Ca-oil scale, or any combination thereof may bereduced or even eliminated due to the complete chemical degradation ofthe polymer.

Advantageously, those of ordinary skill in the art will appreciate thatthe viscosity reducer may oxidize the polymer to reduce its viscosityand molecular size. The viscosity reducer reduces the polymer molecularweight and consequently reduces viscosity of the fluid to near that ofpolymer-free fluid (e.g., water), allowing a more rapid and efficientoil-water separation and minimizing the amount of water-in-oil (WIO) andoil-in-water (OIW) emulsions. Indeed, degrading the polymer allowspractically any emulsion, for example, caused by produced surfactants,to be treated effectively by demulsifiers. Indeed, the viscosity reducermay allow for faster and more efficient oil-water separation byconventional chemical demulsifiers.

Advantageously, those of ordinary skill in the art will appreciate thebenefits of complete neutralization. For example, any excess viscosityreducer has undergone complete neutralization (e.g., by neutralizing anyfree oxygen in the oil-free water) to render the fluid better suitableor suitable for re-injecting, discharging, mixing additional polymer, orany combination thereof after processing. Indeed, neutralizing excessviscosity reducer ensures that the fluid (e.g., separated water of thefluid) may be safely used for re-injecting, discharging, mixingadditional polymer, or any combination thereof after processing.Moreover, the complete neutralization of all excess viscosity reducerwill reduce or even prevent corrosion of the surface fluid processingequipment, the downhole fluid lifting equipment, or any combinationthereof due to the excess viscosity reducer.

Advantageously, those of ordinary skill in the art will appreciate thatfewer negative impacts on the surface fluid processing equipment, thedownhole fluid lifting equipment, or any combination thereof may alsoimprove oil-water separation. Complete chemical degradation of thepolymer improves separation of hydrocarbons (e.g., oil) and water influid being produced via the production wellbore. For example, aviscosity reducer, such as an oxidizer, can be used to destroy thepolymer backbone and reduce water viscosity. Furthermore, the oxidizermay also act as a bactericide to eliminate extraneous biologicalactivity. Less corrosion on the surface fluid processing equipment mayalso improve oil-water separation. The water and oil quality afterseparation may also be better as discussed hereinabove.

Advantageously, those of ordinary skill in the art will appreciate thatif the hydrocarbon-bearing formation, the fluid being produced via theproduction wellbore, etc. do not comprise sulfur, then the non-sulfurcontaining viscosity reducer and the non-sulfur containing neutralizermay be selected to maintain a substantially sulfur-free state. Forexample, those of ordinary skill in the art will appreciate that seawater may naturally contain a concentration of sulfur. Nonetheless, inone embodiment, the non-sulfur containing viscosity reducer comprisessodium hypochlorite, sodium chlorite, hydrogen peroxide, Fenton'sreagent, potassium permanganate, fluorine, hydroxyl radical, atomicoxygen, ozone, perhydroxyl radical, hypobromous acid, chlorine dioxide,hypochlorous acid, hypoiodous acid, chlorine, bromine, iodine, or anycombination thereof. In one embodiment, the non-sulfur containingneutralizer comprises ascorbic acid, sodium ascorbate, citric acid, orany combination thereof.

By maintaining the substantially sulfur-free state, some or alldesulfurization processes may be avoided in some embodiments. Forexample, in one embodiment, the fluid without sulfur may be injectedinto the hydrocarbon-bearing formation (that is being produced), adifferent hydrocarbon-bearing formation, or any combination thereof. Inone embodiment, the fluid without sulfur may be discharged as permittedby law. In one embodiment, additional polymer may be added to the fluidwithout sulfur in order increase the viscosity of the fluid withoutsulfur again and re-inject into the hydrocarbon-bearing formation (thatis being produced), a different hydrocarbon-bearing formation, or anycombination thereof. Indeed, those of ordinary skill in the art willappreciate that by maintaining the substantially sulfur-free state, thefluid without sulfur may be reused more quickly, for example, in anotherEOR process.

FIG. 1 illustrates one embodiment of a method of treating fluidcomprising hydrocarbons, water, and polymer being produced from ahydrocarbon-bearing formation via a production wellbore, referred to asmethod 11. For example, the method 11 may be performed as part of an EORprocess, which is described hereinabove in the hydrocarbon recoverysection.

At step 12, the method 11 includes adding a concentration of a viscosityreducer to the fluid comprising the hydrocarbons, the water, and thepolymer being produced from the hydrocarbon-bearing formation via theproduction wellbore (e.g., at a first location) to degrade the polymerpresent in the fluid. At step 13, the method 11 includes adding aconcentration of a neutralizer to the fluid (e.g., at a second location)to neutralize the viscosity reducer in the fluid. The addition of theconcentration of the viscosity reducer is in a sufficient quantity toallow for complete chemical degradation of the polymer prior to theaddition of the concentration of the neutralizer in the fluid such thatexcess viscosity reducer is present in the fluid. The addition of theconcentration of the neutralizer is sufficiently upstream of any surfacefluid processing equipment to allow for complete neutralization of theexcess viscosity reducer such that excess neutralizer is present in thefluid prior to the fluid reaching any of the surface fluid processingequipment. In one embodiment, the first location is sufficientlyupstream of the second location to allow for complete chemicaldegradation of the polymer prior to the fluid reaching the secondlocation. In one embodiment, the second location is sufficientlyupstream of any of the surface fluid processing equipment to allow forcomplete neutralization of the excess viscosity reducer in the fluidprior to the fluid reaching any of the surface fluid processingequipment.

In some embodiments, such as, but not limited to when the first locationand the second location are different, the concentration of theviscosity reducer and the concentration of the neutralizer may be addedcontinuously to the fluid. In some embodiments, such as, but not limitedto when the first location and the second location are substantially thesame location, the concentration of the viscosity reducer and theconcentration of the neutralizer may be added in batch to the fluid.Furthermore, it is worth noting that the concentration of the viscosity,the concentration of the neutralizer, or any combination thereof may beadjusted (e.g., via dosing pump setting) in response to the polymerconcentration in the fluid being produced.

After step 13, the fluid will pass to the surface fluid processingequipment for separation at step 14. For example, the hydrocarbons willbe separated from the fluid and the water of the fluid may be reused ordischarged. Moreover, the fluid, and more specifically, the separatedwater of the fluid, will be more suitable for re-injecting (step 15),discharging (step 16), mixing additional polymer (step 17), or anycombination thereof due to the complete chemical degradation of thepolymer and complete neutralization of the viscosity reducer.

The actual concentration of the viscosity reducer to be added in orderfor the polymer to undergo complete chemical degradation may bedetermined in a laboratory setting using a viscometer. Complete chemicaldegradation of the polymer is accomplished when the viscosity of thewater returns to the viscosity of a polymer-free version of that type ofwater. For example, after the EOR process has commenced, one or moresamples using the fluid being produced via the production wellbore maybe prepared. If the sample(s) includes hydrocarbons, the hydrocarbonsmay be removed with a separator in the laboratory setting from thesample(s) so that the hydrocarbons do not affect the viscositymeasurements. Alternatively, the sample(s) may be prepared using fluidcollected after the hydrocarbons have been separated by the surfacefluid processing equipment. Alternatively, the sample(s) may be createdusing ion chromatography without hydrocarbons. Some embodiments includedetermining the concentration of the viscosity reducer to add to thefluid for complete chemical degradation of the polymer by using at leastone hydrocarbon-free sample representative of the fluid, whereindetermining the concentration of the viscosity reducer comprises causingthe at least one sample to return to having a polymer-free viscosity,causing the at least one sample to have a viscosity of less than 1.4 cpwith a minimum of 0.9 cp, causing excess viscosity reducer to be presentin the at least one sample, or any combination thereof. FIGS. 11A, 11B,and 11C illustrate different views of apparatuses that may be used inthe laboratory setting to determine the concentration of viscosityreducer for complete chemical degradation of the polymer, theconcentration of neutralizer for complete neutralization of all excessviscosity reducer, or any combination thereof according to the presentdisclosure. Such measurements can also be taken in the field, e.g.,using inline viscometers.

As a first example, assuming the water used in the EOR process is freshwater, fresh water without any polymer has a viscosity of 1 centipoise(cp) at 20° C. Experiments may be run using the viscometer in thelaboratory setting with the sample(s) of the fluid being produced viathe production wellbore to determine what concentration of the viscosityreducer will return the viscosity of the fresh water in the sample(s) tothe viscosity of 1 cp at 20° C. of fresh water without any polymer. Forinstance, if the fresh water in the sample(s) is determined to have aviscosity of 100 cp, due to the concentration of polymer in thesample(s), then experiments may be run using the viscometer to determinewhat concentration of the viscosity reducer will cause the viscosity ofthe fresh water in the sample(s) to drop from 100 cp to 1 cp at 20° C.The return to the viscosity of polymer-free fresh water indicates thatthe concentration of polymer in the sample(s) has undergone completechemical degradation.

As another example, assuming the water in the EOR process is sea water,sea water without any polymer has a viscosity of 1.052 cp at 20° C.Experiments may be run using the viscometer in the laboratory settingwith the sample(s) of the fluid being produced via the productionwellbore to determine what concentration of the viscosity reducer willreturn the viscosity of the sea water in the sample(s) to the viscosityof 1.052 cp at 20° C. of sea water without any polymer. For instance, ifthe sea water in the sample(s) is determined to have a viscosity of 100cp, due to the concentration of polymer in the sample(s), thenexperiments may be run using the viscometer to determine whatconcentration of the viscosity reducer will cause the viscosity of thesea water in the sample(s) to drop from 100 cp to 1 cp at 20° C. Thereturn to the viscosity of polymer-free sea water indicates that theconcentration of polymer in the sample(s) has undergone completechemical degradation.

As another example, brine is oftentimes utilized. The viscosity of thebrine at 20° C. may be determined using a viscometer before any polymeris added to the brine. Experiments may be run using the viscometer inthe laboratory setting with the sample(s) of the fluid being producedvia the production wellbore to determine what concentration of theviscosity reducer will return the viscosity of the brine in thesample(s) to the viscosity of the polymer-free version of that brine at20° C. For instance, if the brine in the sample(s) is determined to havea viscosity of 200 cp, due to the concentration of polymer in thesample(s), then experiments may be run using the viscometer to determinewhat concentration of the viscosity reducer will cause the viscosity ofthe brine in the sample(s) to drop from 200 cp to the viscosity of thepolymer-free version of that brine at 20° C. The return to the viscosityof polymer-free brine indicates that the concentration of polymer in thesample(s) has undergone complete chemical degradation.

In short, the complete chemical degradation of the polymer may bedetermined indirectly through the reduction in viscosity of the water toa polymer-free viscosity for that type of water, for example, at ambienttemperature (e.g., 20° C. to 25° C.). The determined concentration ofviscosity reducer, as well as the residence time corresponding to thedetermined concentration of viscosity reducer for complete chemicaldegradation of the polymer in some embodiments, may be utilized in step12.

As another example, in one embodiment, a viscosity of less than 1.4 cp(e.g., less than 1.3 cp, less than 1.2 cp, or less than 1.1 cp) for thesample(s) in the laboratory setting after the addition of the viscosityreducer indicates complete chemical degradation of the polymer. Asanother example, in one embodiment, a viscosity of at least 0.9 cp(e.g., at least 1 cp, at least 1.1 cp, or at least 1.2) for thesample(s) in the laboratory setting after the addition of the viscosityreducer indicates complete chemical degradation of the polymer. Asanother example, in one embodiment, a viscosity of a minimum 0.9 cp andless than 1.4 cp for the sample(s) after the addition of the viscosityreducer indicates complete chemical degradation of the polymer. Asanother example, in one embodiment, a viscosity of a minimum 1.0 cp andless than 1.4 cp for the sample(s) after the addition of the viscosityreducer indicates complete chemical degradation of the polymer. Asanother example, in one embodiment, a viscosity of 0.9 cp-1.3 cp, 0.9cp-1.2 cp, 0.9 cp-1.1 cp, 1 cp-1.3 cp, 1 cp-1.2 cp, 1 cp-1.1 cp, or 1.1cp or 1.3 cp for the sample(s) in the laboratory setting after theaddition of the viscosity reducer indicates complete chemicaldegradation of the polymer. The viscosity can be determined with aviscometer in the laboratory setting. The viscosity of the sample(s) inthe laboratory setting after the addition of the viscosity reducer fromany of the minimum values described above to any of the maximum valuesdescribed above indicates complete chemical degradation of the polymer.

Moreover, the fluid has a viscosity of less than 1.4 cp with a minimumviscosity of 0.9 cp (or a minimum viscosity of 1 cp in some embodiments)after separation of at least some of the hydrocarbons from the fluid bythe surface fluid processing equipment. In one embodiment, a viscosityof less than 1.4 cp (e.g., less than 1.3 cp, less than 1.2 cp, or lessthan 1.1 cp) in the laboratory setting or at the field for a sample ofthe fluid being produced by the production wellbore after the viscosityreducer has been added to the fluid and after the fluid has passedthrough the FWKO or other separation apparatus would also indicatecomplete chemical degradation of the polymer. As another example, in oneembodiment, a viscosity of at least 0.9 cp (e.g., at least 1 cp, atleast 1.1 cp, or at least 1.2) in the laboratory setting or at the fieldfor a sample of the fluid being produced by the production wellboreafter the viscosity reducer has been added to the fluid and after thefluid has passed through the FWKO or other separation apparatus wouldalso indicate complete chemical degradation of the polymer. As anotherexample, in one embodiment, a viscosity of a minimum 0.9 cp and lessthan 1.4 cp in the laboratory setting or at the field for a sample ofthe fluid being produced by the production wellbore after the viscosityreducer has been added to the fluid and after the fluid has passedthrough the FWKO or other separation apparatus would also indicatecomplete chemical degradation of the polymer. As another example, in oneembodiment, a viscosity of a minimum 1 cp and less than 1.4 cp in thelaboratory setting or at the field for a sample of the fluid beingproduced by the production wellbore after the viscosity reducer has beenadded to the fluid and after the fluid has passed through the FWKO orother separation apparatus would also indicate complete chemicaldegradation of the polymer. As another example, in one embodiment, aviscosity of 0.9 cp-1.3 cp, 0.9 cp-1.2 cp, 0.9 cp-1.1 cp, 1 cp-1.3 cp, 1cp-1.2 cp, 1 cp-1.1 cp, or 1.1 cp or 1.3 cp in the laboratory setting orat the field for a sample of the fluid being produced by the productionwellbore after the viscosity reducer has been added to the fluid andafter the fluid has passed through the FWKO or other separationapparatus would also indicate complete chemical degradation of thepolymer. The viscosity can be determined with a viscometer or in-lineviscometer. The viscosity in the laboratory setting or at the field fora sample of the fluid being produced by the production wellbore afterthe viscosity reducer has been added to the fluid and after the fluidhas passed through the FWKO or other separation apparatus from any ofthe minimum values described above to any of the maximum valuesdescribed above indicates complete chemical degradation of the polymer.

Also, of note, the presence of excess viscosity reducer may alsoindicate that the polymer has undergone complete chemical degradation.For example, the excess viscosity reducer may be present in thesample(s) because the polymer has degraded and there is no more polymerleft to react with the viscosity reducer, hence the excess viscosityreducer. Any quantity of viscosity reducer after the viscosity reducerand the polymer reaction may be considered excess viscosity reducer,such as viscosity reducer of at least one 1 ppm, viscosity reducer in arange of 1 ppm to 10 ppm, excess viscosity reducer in a range of 1 ppmto 25 ppm, excess viscosity reducer in a range of 1 ppm to 50 ppm,excess viscosity reducer in a range of 1 ppm to 75 ppm, excess viscosityreducer in a range of 1 ppm to 100 ppm, etc. Whether or not excessviscosity reducer is present in the sample(s) may be determined withtitration in the laboratory setting. For example, titration may beutilized to determine that a particular sample contains 25 ppm of excessviscosity reducer.

Also, of note, complete chemical degradation of the polymer in thesample(s) may also be determined via gel permeation chromatography(GPC). For example, GPC may be utilized to determine if the molecularchains have shortened. For example, the GPC may be utilized to determineif the polymer in the sample(s), such as polymers with smaller molecularchains like HPAM, have shortening of molecular chains after the additionof the viscosity reducer. Shortening of molecular chains may indicatecomplete chemical degradation of the polymer. GPC may therefore also beutilized to determine the concentration of the viscosity reducer thatwill cause complete chemical degradation of the polymer.

The actual concentration of the neutralizer to be added in order forcomplete neutralization of all excess viscosity reducer may bedetermined in the laboratory setting. Complete neutralization of allexcess viscosity reducer is accomplished when excess neutralizer ispresent. For example, experiments may continue on the sample(s) with theexcess viscosity reducer after complete chemical degradation of thepolymer (or experiments may be run on different sample(s) having thedetermined concentration of viscosity reducer or quantity of viscosityreducer similar to the excess viscosity reducer) to determine whatconcentration of the neutralizer to utilize to accomplish completeneutralization of the excess viscosity reducer in the sample(s) so as toresult in excess neutralizer in the sample(s). Some embodiments includedetermining the concentration of the neutralizer to add to the fluid forcomplete neutralization of the excess viscosity reducer in the fluid byusing at least one hydrocarbon-free sample representative of the fluid,wherein determining the concentration of the neutralizer comprisescausing excess neutralizer to be present in the at least one sample. Theexcess neutralizer is present because the excess viscosity reducer hasbeen neutralized and there is no more viscosity reducer to react withthe neutralizer, hence the excess neutralizer. Any quantity ofneutralizer after the excess viscosity reducer and the neutralizerreaction may be considered excess neutralizer, such as excessneutralizer of at least one 1 ppm, excess neutralizer in a range of 1ppm to 10 ppm, excess neutralizer in a range of 1 ppm to 25 ppm, excessneutralizer in a range of 1 ppm to 50 ppm, excess neutralizer in a rangeof 1 ppm to 75 ppm, excess neutralizer in a range of 1 ppm to 100 ppm,etc.

Whether or not there is excess neutralizer in the sample(s) may bedetermined via titration (with the viscosity reducer) in the laboratorysetting at ambient temperature (e.g., 20° C. to 25° C.). For instance,the remaining neutralizer would be reacted with a titrant duringtitration. The reaction of neutralizer and titrant is 1:1. Depending onhow much titrant gets used, the amount of neutralizer remaining would bedetermined. If this is a 1:2 reaction and say in titration the titrantused is x moles, then the amount of neutralizer present would be x/2moles.

As an example, in the laboratory setting using titration, assume thesample contains 25 ppm of excess viscosity reducer and 125 ppm ofneutralizer is added to the sample at a ratio of the viscosity reducerto the neutralizer of 1:5. After the viscosity reducer and theneutralizer react, excess neutralizer of more than 0 ppm remains in thesample. The excess neutralizer that remains may be a non-sulfurcontaining neutralizer that comprises ascorbic acid, sodium ascorbate,citric acid, or any combination thereof. The excess neutralizerindicates that the excess viscosity reducer of 25 ppm has undergonecomplete neutralization.

In short, the complete neutralization of the viscosity reducer may bedetermined indirectly through the presence of the excess neutralizer.The determined concentration of neutralizer, as well as the residencetime corresponding to the determined concentration of neutralizer forcomplete neutralization of all excess viscosity reducer in someembodiments, may be utilized in step 13. In some embodiments,determining the concentration of the viscosity reducer, theconcentration of the neutralizer, or both comprises using a viscometer,titration, high performance liquid chromatography, or any combinationthereof.

The first location and the second location may vary in the steps 12-13.During the EOR process, the injection fluid containing polymer and wateramong other components is injected into the injection wellbore, and theinjection fluid flows through the hydrocarbon-bearing formation towardsthe production wellbore picking up the hydrocarbons that are swepttowards the production wellbore. The fluid being produced via theproduction wellbore passes through a wellhead of the production wellboretowards surface fluid processing equipment via surface piping. Forexample, the first location and the second location may depend on theavailable equipment, order of the equipment, distance between equipment,residence time for complete chemical degradation of the polymer,residence time for complete neutralization of all excess viscosityreducer, etc.

In one embodiment, the first location is downstream of the wellhead ofthe production wellbore. In one embodiment, the first location is priorto any downhole fluid lifting equipment in the production wellbore. Inone embodiment, the surface fluid processing equipment comprises a FWKO,and the second location is upstream of the FWKO. In one embodiment, thesurface fluid processing equipment comprises a HX downstream of theFWKO, and the second location is upstream of the FWKO. In oneembodiment, the surface fluid processing equipment comprises a separatordownstream of the HX, and the second location is upstream of the FWKO.In one embodiment, the surface fluid processing equipment comprises aflotation cell, an IFG apparatus, a hydrocyclone, a filter, or anycombination thereof downstream of the FWKO, and the second location isupstream of the FWKO. In one embodiment, the first location and thesecond location are upstream of the FWKO.

As an example, assume 400 ppm of the polymer in the fluid being producedvia the production wellbore, 100 ppm of the viscosity reducer is addedfor complete chemical degradation of the 400 ppm of the polymer, and 150ppm of the neutralizer is added to completely neutralize 50 ppm ofexcess viscosity reducer per experiments run in the laboratory setting.At the first location, 100 ppm of the viscosity reducer is added at aratio of the polymer to the viscosity reducer of 4:1 by concentration sothat the polymer undergoes complete chemical degradation. As theviscosity reducer reacts with the polymer and the polymer undergoescomplete chemical degradation, the viscosity of the water of the fluidreturns to a polymer-free viscosity for that type of water and theconcentration of the viscosity reducer may lower to 50 ppm. Thus, theexcess viscosity reducer is 50 ppm in this example. Afterwards, at thesecond location, 150 ppm of the neutralizer is added for completeneutralization of the 50 ppm of excess viscosity reducer at a ratio ofthe excess viscosity reducer to the neutralizer of 1:3. Excessneutralizer of more than 0 ppm remains in the fluid (e.g., at least 1ppm of the excess neutralizer, at least 5 ppm of the excess neutralizer,etc.) as confirmation that the excess viscosity reducer has beencompletely neutralized. The excess neutralizer that remains may be anon-sulfur containing neutralizer that comprises ascorbic acid, sodiumascorbate, citric acid, or any combination thereof. The fluid (e.g.,separated water of the fluid) in this example is more suitable forre-injecting, discharging, mixing additional polymer, or any combinationthereof due to the complete chemical degradation of the polymer andcomplete neutralization of the excess viscosity reducer.

After separation at step 14, the separated water of the fluid may flowto a step 15, a step 16, a step 17, or any combination thereof. At step15, the method 11 includes re-injecting the separated water of the fluidafter the step 14. For example, after the complete chemical degradationof the polymer and after the complete neutralization of all excessviscosity reducer, the separated water of the fluid may be re-injectedinto the hydrocarbon-bearing formation, a different hydrocarbon-bearingformation, or any combination thereof. The separated water of the fluidmay be re-injected into the hydrocarbon-bearing formation through thesame injection wellbore used in this EOR process, through a differentinjection wellbore drilled into the hydrocarbon-bearing formation, orany combination thereof. The separated water of the fluid may bere-injected into one or more injection wellbores drilled into thedifferent hydrocarbon-bearing formation. The separated water of thefluid may be re-injected using substantially the same design, equipment,and methodologies that were used in this EOR process.

At step 16, the method 11 includes discharge of the separated water ofthe fluid after the step 14. For example, after the complete chemicaldegradation of the polymer and after the complete neutralization of allexcess viscosity reducer, the separated water of the fluid may bedischarged as permitted by law.

At step 17, the method 11 includes mixing additional polymer (sometimesreferred to as fresh polymer” into the separated water of the fluidafter step 14. For example, after the complete chemical degradation ofthe polymer and after the complete neutralization of all excessviscosity reducer, additional polymer may be mixed into the separatedwater of the fluid, such as at a third location, in order to increasethe viscosity of the separated water of the fluid again. For example,the third location is downstream of the second location. For example,the separated water of the fluid may flow to a main line and additionalpolymer may be mixed with the separated water of the fluid, such aswhere at least one mixer is positioned for mixing polymer and/or mixinginjection fluid, before injection into an injection wellbore. Aftermixing the additional polymer into the separated water of the fluid, theseparated water of the fluid with increased viscosity due to theadditional polymer may be re-injected into the hydrocarbon-bearingformation, the different hydrocarbon-bearing formation, or anycombination thereof as in step 15. If the non-sulfur containingviscosity reducer and the non-sulfur containing neutralizer wereutilized, then a substantially sulfur-free state may be maintained,which may allow the separated water of the fluid to be reused morequickly.

The additional polymer to be mixed into the separated water of the fluidat step 17 may have substantially the same characteristics as thepolymer at the start of the EOR process before the fluid started to beproduced from the hydrocarbon-bearing formation via the productionwellbore. For example, one or more of the following characteristics maybe substantially the same for the additional polymer mixed into theseparated water of the fluid at step 17 and the polymer at the start ofthe EOR process: (a) type of polymer (e.g., powder polymer, liquidpolymer, etc.), (b) concentration of polymer, (c) constituents of thepolymer if applicable (e.g., all of the constituents, such as polymer,mineral oil, water, chelating agent, alkali, emulsifier, surfactant,biocide, solvent, co-solvent, optional additive, electrolyte, base, anycombination thereof, etc.), (d) polymer mixing equipment and techniques,etc. For example, the polymer at the start of the EOR process and theadditional polymer are substantially the same polymer because they areboth synthetic polymers with similar constituents and similarconcentrations.

However, in some embodiments, one or more characteristics of theadditional polymer may be different as compared to the polymer at thestart of the EOR process, for example, if it is believed that thedifference may improve hydrocarbon recovery. As an example, theconcentration of the additional polymer may be higher as compared to theconcentration of the polymer at the start of the EOR process to improvehydrocarbon recovery. As another example, the polymer at the start ofthe EOR process and the additional polymer have substantially the sameconstituents, but in different concentrations, etc.

In one embodiment, 50 ppm to 50,000 ppm of additional polymer may bemixed into the separated water of the fluid at step 17, as illustratedin Table 1 below. In a second embodiment, 50 ppm to 10,000 ppm ofadditional polymer may be mixed into the separated water of the fluid atstep 17. In a third embodiment, 50 ppm to 5,000 ppm of additionalpolymer may be mixed into the separated water of the fluid at the step17. Furthermore, in some embodiments, one or more other components mayalso be added to the separated water of the fluid before, after, or atabout the same time as the additional polymer. Optionally, anelectrolyte may be added to the separated water of the fluid of 1 ppm to50,000 ppm. Optionally, a surfactant may be added to the separated waterof the fluid of 1,000 ppm to 50,000 ppm. Optionally, a co-solvent may beadded to the separated water of the fluid of 1,000 ppm to 100,000 ppm,and so on. Table 1 illustrates various components that may also beadded.

TABLE 1 Polymer 50 ppm to 50,000 ppm (and its constituents) Surfactant1,000 ppm to 50,000 ppm Co-solvent 1,000 ppm to 100,000 ppm Alkali 100ppm to 25,000 ppm Chelant 1 ppm to 5,000 ppm Mineral Oil 1 ppm to 5,000ppm Electrolyte 1 ppm to 50,000 ppm Biocide 1 ppm to 1,000 ppm

In short, those of ordinary skill in the art will appreciate thatvarious options are available regarding the additional polymer andmixing the additional polymer. For example, if the system includes acollection vessel, the additional polymer may be mixed into theseparated water of the fluid after the fluid exits the collectionvessel. Alternatively, the additional polymer may be mixed into theseparated water of the fluid while the separated water of the fluid ishoused in the collection vessel. Nonetheless, the additional polymer maybe mixed into the separated water of the fluid at step 17 as discussedhereinabove in the hydrocarbon recovery section, and the separated waterof the fluid with the additional polymer may be re-injected as discussedhereinabove at the step 15.

Those of ordinary skill in the art will appreciate that variousmodifications may be made to the method 11 and other embodimentsprovided herein. For example, complete chemical degradation of thepolymer may be detected if the fluid has a viscosity of less than 1.4 cpwith a minimum viscosity of 0.9 cp after separation of at least some ofthe hydrocarbons from the fluid by the surface fluid processingequipment. For example, the method 11 of FIG. 1 may include at least onestep to check the viscosity of the fluid after mixing of the additionalpolymer into the separated water of the fluid at the step 17 and beforere-injecting at the step 15. The viscosity of the separated water of thefluid may be checked using a viscometer, such as the in-line viscometerand systems and methods described in U.S. Patent Application PublicationNo. 2013/0298644, which is incorporated by reference. Alternatively, theviscosity of the separated water of the fluid may be checked using theportable apparatus and systems and methods described in U.S. PatentApplication Publication No. 2018/0031462, each of which is incorporatedby reference. The method 11 may also include a step of adding at leastone demulsifier to the fluid, for example, before any of the surfacefluid processing equipment to help separate the hydrocarbons and thewater of the fluid. By doing so, less water may flow through theseparator due to the addition of the demulsifier.

FIG. 2 illustrates one embodiment of a system of treating fluidcomprising hydrocarbons, water, and polymer being produced from ahydrocarbon-bearing formation via a production wellbore. FIG. 2schematically illustrates an exemplary multilayered hydrocarbon-bearingformation (or subterranean reservoir) 20. The hydrocarbon-bearingformation 20 can be any type of subsurface formation in whichhydrocarbons are stored, such as limestone, dolomite, oil shale,sandstone, or any combination thereof. As illustrated in FIG. 2,production wellbores 30, 34 and injection wellbore 32 are drilled andcompleted in the hydrocarbon-bearing formation 20. Production orinjection wellbores can deviate from the vertical position such that insome embodiments, one or more wellbores can be a directional wellbore,horizontal wellbore, or a multilateral wellbore. In embodiments, feweror additional injection wellbores and/or production wellbores can alsoextend into hydrocarbon-bearing zones 22, 24 of the hydrocarbon-bearingformation 20. The hydrocarbon-bearing formation 20 includes a pluralityof rock layers including the hydrocarbon-bearing strata or zones 22, 24.In embodiments, the hydrocarbon-bearing formation 20 may include adifferent number of zones than those illustrated in FIG. 2.

The production wellbores 30, 34 and the injection wellbore 32 extendinto one or more of the plurality of rock layers (e.g.,hydrocarbon-bearing strata or zones 22, 24) of the hydrocarbon-bearingformation 20 such that the production wellbores 30, 34 and the injectionwellbore 32 are in fluid communication with the hydrocarbon-bearingzones 22, 24. As part of the EOR process, the injection wellbore 32 caninject fluid 57 (e.g., injection fluid) that includes polymer and waterinto the hydrocarbon-bearing zones 22, 24. The fluid 57 may be mixed onsite on the surface 40. The fluid 76, 80 being produced from thehydrocarbon-bearing formation 20 via the production wellbores 30, 34comprise hydrocarbons from the hydrocarbon-bearing formation 20, some orall of the water from the fluid 57 injected into the injection wellbore32, and some or all of the polymer from the fluid 57 injected into theinjection wellbore 32 as a result of the EOR process.

The production wellbores 30, 34 and the injection wellbore 32 alsofluidly connect the hydrocarbon-bearing zones 22, 24 to surface 40 ofthe hydrocarbon-bearing formation 20. The surface 40 of thehydrocarbon-bearing formation 20 can be a ground surface as depicted inFIG. 2, or a platform surface or seafloor in an offshore environment.The production wellbores 30, 34 and the injection wellbore 32 fluidlyconnect with a surface facility comprising surface fluid processingequipment 41 on the surface 40. For example, the surface fluidprocessing equipment 41 may include equipment such as, but not limitedto, a FWKO, a HX, a separator, a flotation cell, an IGF apparatus, ahydrocyclone, a filter, etc. as illustrated in more detail in FIGS. 3-4.

The production or injection wellbores may be completed in any manner(e.g., an openhole completion, a cemented casing and/or linercompletion, a gravel-packed completion, etc.). As shown in FIG. 2,completions 42, 44, 46, 50, 52 provide fluid communication between theinjection wellbore 32, the hydrocarbon-bearing zones 22, 24, and theproduction wellbores 30, 34. Perforations can also be utilized for fluidcommunication. The production wellbore 34 only connects with upperhydrocarbon-bearing zone 22. Each of the production wellbores 30, 34 andthe injection wellbore 32 may include a wellhead, such as wellheads 53,55, 59. Chokes or well control devices 54, 56, 60 of the wellheads 53,55, 59 are used to control the flow of the fluid 57 into the injectionwellbore 32 and control the flow of fluid 76, 80 out of the productionwellbores 30, 34. Well control devices 54, 56, 60 also control thepressure profiles in the production wellbores 30, 34 and the injectionwellbore 32. From the wellheads 53, 59, the fluid 76, 80 being producedby the production wellbores 30, 34 flows to the surface fluid processingequipment 41.

The production wellbores 30, 34 may include downhole fluid liftingequipment such as electric submersible pumps (ESPs) 64, 70 to lift thefluid 76, 80 up through the production wellbores 30, 34 to the wellheads53, 59. The ESPs 64, 70 may be coupled to ESP cables 66, 72, forexample, to provide power to the ESPs 64, 70. The ESPs 64, 70 may bepositioned in practically any location within the production wellbores30, 34 to lift the fluid 76, 80 to the wellheads 53, 59.

In some embodiments, at least a portion of an ESP may be coated with acoating to reduce polymer adherence. In some embodiments, at least aportion of the ESP which is in contact with fluid during operation ofthe ESP is coated with a coating to reduce polymer adherence. In certainembodiments, substantially all of the ESP which is in contact with fluidduring operation of the ESP is coated with a coating to reduce polymeradherence. Depending on the composition of the coating as well as thesurface(s) of the ESP which are coated, the coating can be applied toESP surfaces prior to assembly of the ESP, at a suitable stage duringassembly of the ESP, after assembly of the ESP, or any combinationthereof. For example, in the case of coatings that require curing stepswhich may damage electronic components (e.g., coatings that aredeposited using thermal curing), coatings may be deposited on surface(s)of components of the ESP before and/or during assembly, but prior toassembly of the motor and/or other electronic components of the ESP.Likewise, in the case of coatings that require irradiation of coatedsurfaces as part of the curing step (e.g., coatings that are depositedusing a UV curing step), coatings may be deposited on surface(s) ofcomponents of the ESP before and/or during assembly (when they can bereadily irradiated with UV light), and then the ESP can be assembled.

A variety of suitable coatings are known in the art. By way of example,in some embodiments, the coating can comprise an organic-inorganichybrid coating. Such coatings may be formed using a sol-gel comprising asilane, silanol, metal oxide precursor, a derivative thereof, orcombination thereof deposited on a surface of a substrate (a surface ofthe ESP or a component thereof). Such coatings can include base chemicalreagent(s) to form the body of the base composite. In some embodiments,the composite solution can further include chelating agent(s) to enhancehomogeneity of the organic/inorganic material(s) in the solution,bonding agent(s) to aid bonding of the composite to a desired surface,plasticizer(s) to maintain elasticity of the base composite, viscositymodifier(s) to achieve a desired viscosity for the solution, hydrophobicchemical agent(s) to increase the surface hydrophobicity of theresulting composite, or any combination thereof. In some embodiments, asurface treatment comprising hydrophobic chemical agent(s) may beapplied after deposition of the sol-gel to increase the surfacehydrophobicity of the resulting composite. Examples of such coatings aredescribed, for example, in U.S. Patent Application Publication No.2017/0313888, which is hereby incorporated by reference in its entirety.

The base chemical reagent(s) to form the body of the base composite maycomprise at least one alkoxysilane, metal oxide precursor, or anycombination thereof having a general formula of M(OR)₄ (M=Si, Al, Ti,In, Sn, or Zr), where R comprises hydrogen, a substituted orunsubstituted alkyl, or derivatives thereof. Nonlimiting examples ofsuch chemicals includes tetramethyl orthosilicate, tetraethylorthosilicate, tetraisopropyl orthosilicate, tetra(tert-butyl)orthosilicate, tetra(sec-butyl) orthosilicate, aluminum methoxide,aluminum ethoxide, aluminum isopropoxide, aluminum tert-butoxide,aluminum tri-sec-butoxide, titanium methoxide, titanium ethoxide,titanium isopropoxide, titanium tert-butoxide, titaniumtri-sec-butoxide, and derivatives bearing similar structures.

Example chelating agent(s) to enhance homogeneity of the organicmaterial(s) in the solution may comprise at least one alkoxysilane,metal oxide precursor, or any combination thereof having a generalformula of M(OR)_(x)R′_(y)R″_(z) (M=Si, Al, In, Sn, or Ti; x is theinteger 1, 2 or 3; y is the integer 0, 1 or 2; z is the integer 1, 2 or3, provided that the sum of x, y and z equals 4), where R compriseshydrogen, a substituted or unsubstituted alkyl, or derivatives thereof;R′ comprises hydrogen, a substituted or unsubstituted alkyl, orderivatives thereof, and R″ comprises a substituted or unsubstitutedalky or alkenyl group comprising from 3 to 20 carbon atoms. Nonlimitingexamples of such chemicals include trimethoxyphenylsilane,dimethoxymethylphenylsilane, methoxydimethylphenylsilane,trimethoxyphenethylsilane, dimethoxymethylphenethylsilane,methoxydimethylphenethylsilane, trimethoxyoctylsilane,dimethoxymethyloctylsilane, methoxydimethyloctylsilane,trimethoxydodecylsilane, dimethoxymethyldodecylsilane,methoxydimethyldodecylsilane, trimethoxydecylsilane,dimethoxymethyldecylsilane, methoxydimethyldecylsilane,trimethoxyoctadecylsilane, dimethoxymethyloctadecylsilane,methoxydimethyloctadecylsilane, trimethoxyhexylsilane,dimethoxymethylhexylsilane, methoxydimethylhexylsilane,trimethoxy(cyclohexylmethyl)silane,dimethoxymethyl(cyclohexylmethyl)silane,methoxydimethyl(cyclohexylmethyl)silane, triethoxyphenylsilane,diethoxymethylphenylsilane, ethoxydimethylphenylsilane,triethoxyphenethylsilane, diethoxymethylphenethylsilane,ethoxydimethylphenethylsilane, triethoxyoctylsilane,diethoxymethyloctylsilane, ethoxydimethyloctylsilane,triethoxydodecylsilane, diethoxymethyldodecylsilane,ethoxydimethyldodecylsilane, triethoxydecylsilane,diethoxymethyldecylsilane, ethoxydimethyldecylsilane,triethoxyoctadecylsilane, diethoxymethyloctadecylsilane,ethoxydimethyloctadecylsilane, triethoxyhexylsilane,diethoxymethylhexylsilane, ethoxydimethylhexylsilane,triethoxy(cyclohexylmethyl)silane,diethoxymethyl(cyclohexylmethyl)silane,ethoxydimethyl(cyclohexylmethyl)silane, and derivatives bearing similarstructures.

Example chelating agent(s) to enhance homogeneity of the inorganicmaterial(s) in the solution may comprise at least one alkoxysilane,metal oxide precursor, or any combination thereof having a generalformula of M(OR)_(x)R′_(y)R″_(z) (M=Si, Al, In, Sn, or Ti; x is theinteger 1, 2 or 3; y is the integer 0, 1 or 2; z is the integer 1, 2 or3, provided that the sum of x, y and z equals 4), where R compriseshydrogen, a substituted or unsubstituted alkyl or derivatives thereof;R′ comprises hydrogen, a substituted or unsubstituted alkyl, orderivatives thereof and R″ comprises a substituted or unsubstitutedamine (including primary, secondary and tertiary) or thiol. Nonlimitingexamples of such chemicals includes 3-aminopropyltrimethoxysilane,3-aminopropyltriethoxysilane, 2-aminoethyltrimethoxysilane,2-aminoethyltriethoxysilane, N-methylaminopropyltrimethoxysilane,N-methylaminopropyltriethoxysilane 4-aminobutylmethyldimethoxysilane,4-aminobutylmethyldiethoxysilane, 3-aminopropyldimethylmethoxysilane,3-aminopropyldimethylethoxysilane, 3-aminopropylmethyldimethoxysilane,3-aminopropylmethyldiethoxysilane,N,N-dimethyl-3-aminopropyltrimethoxysilane,N,N-dimethyl-3-aminopropyltriethoxysilane,N,N-diethyl-3-aminopropyltrimethoxysilane,N,N-diethyl-3-aminopropyltriethoxysilane,N,N-diethylaminomethyltrimethoxysilane,N,N-diethylaminomethyltriethoxysilane,bis(2-hydroxyethyl)-3-aminopropyltrimethoxysilane,bis(2-hydroxyethyl)-3-aminopropyltriethoxysilane,N-(2′-aminoethyl)-3-aminopropyltrimethoxysilane,N-(2′-aminoethyl)-3-aminopropyltriethoxysilane,N-butyl-3-aminopropyltrimethoxysilane,N-butyl-3-aminopropyltriethoxysilane,N-octyl-3-aminopropyltrimethoxysilane,N-octyl-3-aminopropyltriethoxysilane,N-cyclohexyl-3-aminopropyltrimethoxysilane,N-cyclohexyl-3-aminopropyltriethoxysilane,N-(3′-trimethoxysilylpropyl)-piperazine,N-(3′-triethoxysilylpropyl)-piperazine,N-(3′-trimethoxysilylpropyl)morpholine,N-(3′-triethoxysilylpropyl)morpholine,bis(3-trimethoxysilylpropyl)amine, bis(3-triethoxysilylpropyl)amine,tris(3-trimethoxysilylpropyl)amine, tris(3-triethoxysilylpropyl)amine,N-methyl-N-butyl-3-aminopropyltrimethoxysilane,N-methyl-N-butyl-3-aminopropyltriethoxysilane,N-(3′-aminopropyl)-3-aminopropyltrimethoxysilane,N-(3′-aminopropyl)-3-aminopropyltriethoxysilane,N-phenyl-3-aminopropyltrimethoxysilane,N-phenyl-3-aminopropyltriethoxysilane, 3-mercaptopropyltrimethoxysilane,3-mercaptopropyltriethoxysilane, and derivatives bearing similarstructures.

Example bonding agent(s) to aid bonding of the organic/inorganiccomposite to a desired surface may comprise at least one alkoxysilane,metal oxide precursor, or any combination thereof having a generalformula of M(OR)_(x)R′_(y)R″_(z) (M=Si, Al, In, Sn, or Ti; x is theinteger 1, 2 or 3; y is the integer 0, 1 or 2; z is the integer 1, 2 or3, provided that the sum of x, y and z equals 4), where R compriseshydrogen, a substituted or unsubstituted alkyl, or derivatives thereof;R′ comprises hydrogen, a substituted or unsubstituted alkyl, orderivatives thereof; and R″ comprises a substituted or unsubstitutedepoxy or glycidoxy. Nonlimiting examples of such chemicals includes2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane,2-(3,4-epoxycyclohexyl)-ethyltriethoxysilane,5,6-epoxyhexyltrimethoxysilane, 5,6-epoxyhexyltriethoxysilane,glycidoxymethyltrimethoxysilane, glycidoxymethyltriethoxysilane,2-glycidoxyethyltrimethoxysilane, 2-glycidoxyethyltriethoxysilane,3-glycidoxypropyltrimethoxysilane, 3-glycidoxypropyltriethoxysilane,4-glycidoxybutyltrimethoxysilane, 4-glycidoxybutyltriethoxysilane, andderivatives bearing similar structures.

Example plasticizer(s) to maintain elasticity of the base composite maycomprise at least one alkoxysilane, metal oxide precursor, or anycombination thereof having a general formula of M(OR)_(4-x)R′_(x) (M=Si,Al, In, Sn, or Ti; x is the integer 1, 2 or 3), where R comprisehydrogen, a substituted or unsubstituted alkyl, or derivatives thereofand R′ comprise a substituted or unsubstituted alkyl, a substituted orunsubstituted alkenyl, a substituted or unsubstituted alkynyl, asubstituted or unsubstituted aryl, or derivatives thereof. Nonlimitingexamples of such chemicals includes trimethoxymethylsilane,dimethoxydimethylsilane, methoxytrimethylsilane, trimethoxyethylsilane,dimethoxydiethylsilane, methoxytriethylsilane, trimethoxypropylsilane,dimethoxydipropylsilane, methoxytripropylsilane,trimethoxyisobutylsilane, triethoxyisobutylsilane,dimethoxydiisobutylsilane, diethoxydiisobutylsilane,trimethoxyphenylsilane, dimethoxydiphenylsilane, methoxytriphenylsilane,trimethoxyphenethylsilane, dimethoxydiphenethylsilane,methoxytriphenethylsilane, triethoxymethylsilane,diethoxydimethylsilane, ethoxytrimethylsilane, triethoxyethylsilane,diethoxydiethylsilane, ethoxytriethylsilane, triethoxypropylsilane,diethoxydipropylsilane, ethoxytripropylsilane, triethoxyphenylsilane,diethoxydiphenylsilane, ethoxytriphenylsilane, triethoxyphenethylsilane,diethoxydiphenethylsilane, ethoxytriphenethylsilane, and derivativesbearing similar structures.

Example viscosity modifier(s) to achieve a desired viscosity for thesolution may comprise at least one alkylsiloxane in oligomer/co-oligomerform, polymer/co-polymer form, or any combination thereof having ageneral formula of

and average molecular weight equal to or between 100 to 100,000 Da,where R and R′ can be the same or different and comprise hydrogen, asubstituted or unsubstituted alkyl, or derivatives thereof. Nonlimitingexamples of such chemicals include 3-aminopropyl-terminatedpoly(dimethylsiloxane), chlorine-terminated poly(dimethylsiloxane),glycidyl ether-terminated poly(dimethylsiloxane), hydride-terminatedpoly(dimethylsiloxane), hydroxy-terminated poly(dimethylsiloxane),hydroxyalkyl-terminated poly(dimethylsiloxane), vinyl-terminatedpoly(dimethylsiloxane), trimethylsilyl-terminatedpoly(dimethylsiloxane), and derivatives bearing similar structures.

Optionally, functional additives may be incorporated into the coatingcomposition to provide, for example, anti-abrasion, anti-microbial,anti-bacterial, anti-fungal benefits and/or pigmentation. The additivesmay be composed of materials including but not limited to,organic/inorganic molecules/polymers having molecular weight up to about100,000 Da, organic micro/nano materials in their natural or syntheticforms (e.g. particles, nanotubes and nanosheets) having sizes equal toor between about 2 nm to 500 μm; metal/metal oxide micro/nano materials(e.g. silver, titanium oxide, zinc oxide, aluminum oxide, iron oxide,selenium oxide, tellurium oxide and clay, which may be composed ofkaolinite, montmorillonite, illite or chlorite) in their natural orsynthetic forms (e.g. particles, nanotubes and nanosheets) having sizesequal to or between about 2 nm to 500 μm; or any combination thereof.

Coatings can be formed by mixing solvent(s), base chemical reagents(s),chelating agent(s), bonding agent(s), plasticizer(s), viscositymodifier(s), functional additive(s), and/or pigment(s) in an acidiccondition (pH5) to form a coating solution. In some embodiments, acoating solution may comprise at least the solvent(s), base chemicalreagent(s), chelating agent(s), bonding agent(s), and plasticizer(s). Insome embodiments, the coating solution may optionally further includeviscosity modifier(s), functional additive(s) and/or pigment(s). In someembodiments, the coating solution may comprise 1-10 vol. % of water,10-40 vol. % of at least one solvent(s), 30-70 vol. % of at least onebase chemical reagent(s), 10-20 vol. % of at least one plasticizer(s),1-10 vol. % of at least one bonding agent(s), and the rest of the volumemay comprise the chelating agent(s), the viscosity modifier(s), thefunctional additive(s), and/or the pigment(s). In some embodiments, thecoating solution may comprise 3-8 vol. % of water, 20-30 vol. % of atleast one solvent(s), 40-60 vol. % of at least one base chemicalreagent(s), 10-15 vol. % of at least one plasticizer(s), 1-5 vol. % ofat least one bonding agent(s), and the remaining volume may comprise anyoptional additives. In some embodiments, the coating solution is similarto the embodiments above, but the concentration of plasticizer(s) isless than 15 vol. %, or more preferably less than 10 vol. %. In someembodiments, the coating solution is similar to the embodiments above,but the concentration of bonding agent(s) is less than 5 vol. %, or morepreferably less than 3 vol. %. The mixture of the aforementionedchemical agents may be stirred at elevated temperature equal to orbetween 50 to 100° C. for about ½ hour to 10 days, or preferably between50 to 70° C. for about ½ hour to 12 hours. In some embodiments, thecoating solution can be further diluted with more solvent(s) to a finalconcentration no less than 20 vol. % to form the final coating solutionfor application to a surface, such as a final concentration between 60to 100 vol. % (e.g., 80 to 100 vol. %). In some embodiments, theorganic/inorganic composite solution is at least partially hydrolyzed orcompletely hydrolyzed. The coating solution can then be deposited on asurface of the ESP to afford a coating. This can comprise, for example,spraying, misting, doctor-blading, padding, foaming, rolling, inkjetprinting, dipping, flush or dip-coating, immersing, soaking, or anycombination thereof. The solvent may then be removed from the materials,and the materials may be dried or cured at a set temperature equal to orbetween about 25 and 200° C. In certain embodiments, the crosslinkdensity of the crosslinkable components, e.g., the degree ofcrosslinking can range from 1% to 100% of complete crosslinking.

If desired, the target surface may be activated before the deposition ofthe organic/inorganic coating solution. The surface activation may beachieved by reaction with ozone, oxygen, hydrogen peroxide, halogens,other reactive oxidizing species, or any combination thereof. Theactivation can create an energetically reactive surface, increase theconcentration of free radicals, bind molecules on the surfacecovalently, or any combination thereof. In some embodiments, the surfaceactivation may be achieved by ozone plasma generated by intense UVlight. In other embodiments, surface activation may be achieved byplasma treatment. In yet another embodiment, surface activation may beachieved by ozone generation using a corona discharge, flame, or plasma.

If desired, the resulting coatings may then be treated with thehydrophobic chemical agent(s) to increase the surface hydrophobicity ofthe resulting organic/inorganic nanocomposite. This can comprisecontacting the coating with a hydrophobic solution that comprisessolvents, hydrophobic chemical agents and/or other chemical agents,which renders the surface hydrophobic/superhydrophobic, generatesnanoscopic or microscopic topography, or any combination thereof. Insome embodiments, the hydrophobic solution comprises at least onesolvent and a hydrophobic chemical agent. In some embodiments, thehydrophobic solution may further include one or more other chemicalagents. In some embodiments, the hydrophobic chemical agents and/orother chemical agents may be deposited utilizing a vapor treatment.

As a nonlimiting example, in some cases, the hydrophobic chemical agentcan include at least one type of fluoroalkylsilane covalently bonded tothe resulting surface, which renders the surfacehydrophobic/superhydrophobic. The covalently bound fluoroalkylsilane canalso generate nanoscopic or microscopic topography. In some embodiments,the hydrophobic chemical agents may have a general formula offluoroalkylsilane [CF₃(CF₂)_(a)(CH₂)_(b)]_(c)SiR_(d)X_(e) (where X=Cl,Br, I, or other suitable organic leaving groups, R comprises asubstituted or unsubstituted alkyl, a substituted or unsubstitutedalkenyl, a substituted or unsubstituted alkynyl, a substituted orunsubstituted aryl, or derivatives thereof, a is the integer 0, 1, 2, 3. . . to 20, b is the integer 0, 1, 2, 3 . . . to 10, c is the integer1, 2, or 3, d is the integer 0, 1, 2, or 3, and e is the integer 1, 2,or 3, provided that the sum of c, d and e equals 4). Examplefluoroalkylsilane species may include, but are not limited to,trichloro(3,3,3-trifluoropropyl)silane, dichloro-methyl(3,3,3-trifluoropropyl) silane, chloro-dimethyl(3,3,3-trifluoropropyl)silane,trichloro(1H,1H,2H,2H-perfluorobutyl)silane,dichloro-methyl(1H,1H,2H,2H-perfluorobutyl)silane,chloro-dimethyl(1H,1H,2H,2H-perfluorobutyl)silane,trichloro(1H,1H,2H,2H-perfluorohexyl)silane,dichloro-methyl(1H,1H,2H,2H-perfluorohexyl)silane,chloro-dimethyl(1H,1H,2H,2H-perfluorohexyl)silane,trichloro(1H,1H,2H,2H-perfluorooctyl)silane,dichloro-methyl(1H,1H,2H,2H-perfluorooctyl)silane,chloro-dimethyl(1H,1H,2H,2H-perfluorooctyl)silane,trichloro(1H,1H,2H,2H-perfluorodecyl)silane,dichloro-methyl(1H,1H,2H,2H-perfluorodecyl)silane,chloro-dimethyl(1H,1H,2H,2H-perfluorodecyl)silane,trichloro(1H,1H,2H,2H-perfluorododecyl)silane,dichloro-methyl(1H,1H,2H,2H-perfluorododecyl) silane,chloro-dimethyl(1H,1H,2H,2H-perfluorododecyl)silane, and derivativesbearing similar structures. In some embodiments, these hydrophobicchemical agent(s) may be dissolved or dispersed in one or more organicsolvents. The concentration of the hydrophobic chemical agent(s) inorganic solvent(s) is equal to or between 0.1 and 15 vol. %. Exampleorganic solvents may include but not limited to toluene, benzene,xylene, trichloroethylene, 1,2-dichloroethane, dichloromethane,chloroform, carbon tetrachloride, tetrachloroethylene, n-propyl bromide,diethyl ether, acetone, diisopropyl ether, methyl-t-butyl ether,petroleum ethers, and petroleum hydrocarbons.

Other chemical agents may also be used alone or in conjunction withfluoroalkylsilanes to perform similar tasks to render the surfacehydrophobic and/or to generate nanoscopic topography. In someembodiments, other chemical agents may be hydrophobic and may have ageneral formula of alkylsilane [CH₃(CH₂)_(a)]_(b)SiR_(c)X_(d); where Xcomprises Cl, Br, I, or other suitable organic leaving groups, Rcomprises a substituted or unsubstituted alkyl, a substituted orunsubstituted alkenyl, a substituted or unsubstituted alkynyl, asubstituted or unsubstituted aryl, or derivatives thereof, and a is theinteger 0, 1, 2, 3 . . . to 20, b is the integer 1, 2 or 3, c is theinteger 0, 1, 2, or 3, and d is the integer 1, 2 or 3, provided that thesum of b, c and d equals 4. The preferred alkylsilane species mayinclude, but are not limited to, chlorosilane, dichlorosilane,trichlorosilane, chlorotrimethylsilane, dichlorodimethylsilane,trichloromethylsilane, chlorophenylsilane, dichlorophenylsilane,trichlorophenylsilane, chloromethylphenylsilane,chlorodimethylphenylsilane, dichloromethylphenylsilane,chlorodimethylphenethylsilane, dichloromethylphenethylsilane,trichlorophenethylsilane, chlorodimethyloctylsilane,dichloromethyloctylsilane trichlorooctylsilane,chlorodimethyldodecylsilane, dichloromethyldodecylsilane,trichlorododecylsilane, chlorodecyldimethylsilane,dichlorodecylmethylsilane, trichlorodecylsilane,chlorodimethyloctadecylsilane, dichloromethyloctadecylsilane,trichlorooctadecylsilane, chlorodimethylthexylsilane,dichloromethylthexylsilane, trichlorothexylsilane,allyldichloromethylsilane, allylchlorodimethylsilane,allyltrichlorosilane, (cyclohexylmethyl)chlorodimethylsilane,(cyclohexylmethyl)dichloromethylsilane,(cyclohexylmethyl)trichlorosilane, and derivatives bearing similarstructures. In some embodiments, these chemical agent(s) may bedissolved or dispersed in one or more organic solvents. Typically, theconcentration of the hydrophobic chemical agent(s) in organic solvent(s)is equal to or between 0.1 and 15 vol. %. Example organic solvents mayinclude but not limited to toluene, benzene, xylene, trichloroethylene,1,2-dichloroethane, dichloromethane, chloroform, carbon tetrachloride,tetrachloroethylene, n-propyl bromide, diethyl ether, acetone,diisopropyl ether, methyl-t-butyl ether, petroleum ethers, and petroleumhydrocarbons. Other chemical agents may also be used alone or inconjunction with fluoroalkylsilanes or alkylsilanes to perform similartasks to render the surface hydrophobic and/or to generate nanoscopictopography.

Another example hydrophobic chemical agent includes analkoxyfluoroalkylsilane covalently bonded to the resulting surface,which renders the surface hydrophobic/superhydrophobic and/or generatesnanoscopic topography. The hydrophobic chemical agent may have a generalformula of alkoxyfluoroalkylsilane[CF₃(CF₂)_(a)(CH₂)_(b)]_(c)SiR_(d)[alkoxy]_(e) (where [alkoxy] comprisemethoxy, ethoxy, propoxy, isopropoxy, butoxy, isobutoxy, or anycombination thereof; R comprises a substituted or unsubstituted alkyl, asubstituted or unsubstituted alkenyl, a substituted or unsubstitutedalkynyl, a substituted or unsubstituted aryl, or derivatives thereof, ais the integer 0, 1, 2, 3 . . . to 20, b is the integer 0, 1, 2, 3 . . .to 10, c is the integer 1, 2, or 3, d is the integer 0, 1, 2, or 3, ande is the integer 1, 2, or 3, provided that the sum of c, d and e equals4). Example alkoxyfluoroalkylsilane species may include, but are notlimited to, trimethoxy(3,3,3-trifluoropropyl)silane,triethoxy(3,3,3-trifluoropropyl)silane,tripropoxy(3,3,3-trifluoropropyl)silane,triisopropoxy(3,3,3-trifluoropropyl)silane,trimethoxy(1H,1H,2H,2H-perfluorobutyl)silane,triethoxy(1H,1H,2H,2H-perfluorobutyl)silane,tripropoxy(1H,1H,2H,2H-perfluorobutyl)silane,triisopropoxy(1H,1H,2H,2H-perfluorobutyl)silane,trimethoxy(1H,1H,2H,2H-perfluorohexyl)silane,triethoxy(1H,1H,2H,2H-perfluorohexyl)silane,tripropoxy(1H,1H,2H,2H-perfluorohexyl)silane,triisopropoxy(1H,1H,2H,2H-perfluorohexyl)silane,trimethoxy(1H,1H,2H,2H-perfluorooctyl)silane,triethoxy(1H,1H,2H,2H-perfluorooctyl)silane,tripropoxy(1H,1H,2H,2H-perfluorooctyl)silane,triisopropoxy(1H,1H,2H,2H-perfluorooctyl)silane,trimethoxy(1H,1H,2H,2H-perfluorodecyl)silane,triethoxy(1H,1H,2H,2H-perfluorodecyl)silane,tripropoxy(1H,1H,2H,2H-perfluorodecyl)silane,triisopropoxy(1H,1H,2H,2H-perfluorodecyl)silane,trimethoxy(1H,1H,2H,2H-perfluorododecyl)silane,triethoxy(1H,1H,2H,2H-perfluorododecyl)silane,tripropoxy(1H,1H,2H,2H-perfluorododecyl)silane,triisopropoxy(1H,1H,2H,2H-perfluorododecyl)silane, and derivativesbearing similar structures. In some embodiments, these hydrophobicchemical agents may be dissolved or dispersed in an organic solvent or amixture of organic solvents. Typically, the concentration of thehydrophobic chemical agent(s) in organic solvent(s) is equal to orbetween 0.1 and 15 vol. %. Example organic solvents may include, but arenot limited to, methanol, ethanol, n-propanol, isopropanol, n-butanol,isobutanol, acetone, acetonitrile, dioxane, tetrahydrofuran,tetrachloroethylene, n-propyl bromide, dimethylformamide, dimethylsulfoxide, and water.

In some embodiments, the alkoxyfluoroalkylsilane[CF₃(CF₂)_(a)(CH₂)_(b)]_(c)SiR_(d)[alkoxy]_(e) can be chemicallyconverted from fluoroalkylsilane [CF₃(CF₂)_(a)(CH₂)_(b)]_(c)SiR_(d)X_(e)by mixing and heating the fluoroalkylsilane in the correspondingsolvent(s) (e.g. methanol, ethanol, isopropanol, and water). The mixtureof the chemical agent can then be stirred at elevated temperature equalto or between 50 to 100° C. for about 1 hour to 7 days in an acidicenvironment (pH≤1) before being neutralized with KOH (may contain up to15% (by weight) of water) until the pH reached is equal to or between 6and 8. The hydrophobic solutions can then be used directly or furtherdiluted in an appropriate solvent (e.g. methanol, ethanol, isopropanol,denatured ethanol, water, etc.).

Other chemical agents can be use alone or in conjunction with anotheragent (e.g., an alkoxyfluoroalkylsilane) to render the surfacehydrophobic and/or to generate nanoscopic topography. In someembodiments, other chemical agents may be hydrophobic and may have ageneral formula of alkoxyalkylsilane[CH₃(CH₂)_(a)]_(b)SiR_(c)[alkoxy]_(d); where [alkoxy] comprise methoxy,ethoxy, propoxy, isopropoxy, butoxy, isobutoxy, or any combinationthereof; R comprise a substituted or unsubstituted alkyl, a substitutedor unsubstituted alkenyl, a substituted or unsubstituted alkynyl, asubstituted or unsubstituted aryl, or derivatives thereof, and a is theinteger 0, 1, 2, 3 . . . to 20, b is the integer 1, 2 or 3, c is theinteger 0, 1, 2, or 3, and d is the integer 1, 2 or 3, provided that thesum of b, c and d equals 4. Example alkoxyalkylsilane species mayinclude, but are not limited to, trimethoxyisobutylsilane,triethoxyisobutylsilane, dimethoxydiisobutylsilane,diethoxydiisobutylsilane, trimethoxy(hexyl)silane,triethoxy(hexyl)silane, tripropoxy(hexyl)silane,triisopropoxy(hexyl)silane, trimethoxy(octyl)silane,triethoxy(octyl)silane, tripropoxy(octyl)silane,triisopropoxy(octyl)silane, trimethoxy(decyl)silane,triethoxy(decyl)silane, tripropoxy(decyl)silane,triisopropoxy(decyl)silane, trimethoxy(dodecyl)silane,triethoxy(dodecyl)silane, tripropoxy(dodecyl)silane,triisopropoxy(dodecyl)silane, and derivatives bearing similarstructures. In some embodiments, these agent may be dissolved ordispersed in an organic solvent or a mixture of organic solvents. Theconcentration of these agent(s) in organic solvent(s) is equal to orbetween 0.1 and 15 vol. %. Example organic solvents may include, but arenot limited to, methanol, ethanol, n-propanol, isopropanol, n-butanol,isobutanol, acetone, acetonitrile, dioxane, tetrahydrofuran,tetrachloroethylene, n-propyl bromide, dimethylformamide, dimethylsulfoxide, and water. Other chemical agents may also be used alone or inconjunction with alkoxyalkylsilanes to perform similar tasks to renderthe surface hydrophobic and/or to generate nanoscopic topography.

In some embodiments, the alkoxyalkylsilane[Ch₃(CH₂)_(a)]_(b)SIR_(c)[alkoxy]_(d) can be chemically converted fromalkylsilane [CH₃(CH₂)_(a)]_(b)SIR_(c)X_(d) by mixing and heating thefluoroalkylsilane in the correspondent solvent(s) (e.g. methanol,ethanol, isopropanol, and/or water). The mixture of the thereof chemicalagents can be stirred at elevated temperature equal to or between 50 to100° C. for about 1 hour to 7 days in an acidic environment (pH1) beforebeing neutralized with KOH (may contain up to 15% (by weight) of water)until the pH reached is equal to or between 6 and 8. These solutions canthen be used directly or further diluted in an appropriate solvent (e.g.methanol, ethanol, isopropanol, denatured ethanol, water, etc.).

In some embodiments, the coating can comprise a single layer. In otherembodiments, the coating can comprise a multilayer coating comprisingfrom two to five layers. In some embodiments, the coating can comprise ametal-oxide layer (e.g., a SiO₂ layer). For example, in some examples,the coating can comprise an organic-inorganic hybrid layer (e.g.,comprising a metal oxide such as SiO₂) and a hydrophobic surface coating(e.g., a fluoropolymer and/or other hydrophobic chemical agent describedabove). In some embodiments, the coating can comprise anorganic-inorganic hybrid layer and a primer layer to enhance adhesion ofthe organic-inorganic hybrid layer to the surface of the ESP. In someembodiments, the coating can comprise an organic-inorganic hybrid layer,a hydrophobic surface coating (e.g., a fluoropolymer and/or otherhydrophobic chemical agent described above), and a primer layer toenhance adhesion of the organic-inorganic hybrid layer to the surface ofthe ESP. In some examples, the coating can have a total thickness offrom 500 nm to 250 microns (e.g., from 1 micron to 200 microns, or from5 microns to 120 microns). In some embodiments, the coating can exhibita surface energy of 40 mN/m or less (e.g., 35 mN/m or less, 30 mN/m orless, 25 mN/m or less, or 20 mN/m or less). For example, in someembodiments, the coating can exhibit a surface energy of from 10 to 40mN/m.

A wide variety of other suitable coatings and coating materials areknown in the art, including fluoropolymer coatings (e.g.,perfluoroalkoxy alkanes, polytetrafluoroethylene, polyvinylfluoride,polyvinylidene fluoride, polychlorotrifluoroethylene, fluorinatedethylene-propylene, polyethylenetetrafluoroethylene,polyethylenechlorotrifluoroethylene, perfluorinated elastomers such asFFPM, FFKM, FPM, FKM, or FEPM, perfluoropolyether, copolymers thereof,and blends thereof), phenolic coatings, and epoxy coatings. Suitablecoatings and coating components are known in the art, and include thosecoatings described in U.S. Pat. Nos. 9,029,491, 6,288,198, 6,630,205,7,345,131, U.S. Patent Application Publication No. 2008/090010, U.S.Patent Application Publication No. 2003/049486, U.S. Patent ApplicationPublication No. 2007/017402 A1, U.S. Patent Application Publication No.2009/0099287, U.S. Patent Application Publication No. 2008/0090010, U.S.Patent Application Publication No. 2010/0291487, WO 2005/035676, WO2009/030538, DE10106342, DE10153352, DE 102007020404, and DE10200450747, each of which is hereby incorporated by reference in itsentirety. Examples of suitable commercially available coatings andcoating materials include, for example, coatings and coating materialsavailable under the tradename StreaMax™ from Chemours(fluoropolymer-based coating systems), HeatX™ from Oceanit(nanocomposite omniphobic coatings), Curramix™ from Curran (includingepoxy coatings sold under the tradenames Curran 500™, Curran 1000R™,Curran 1200™, Curran 1500™, and Curran 2500™), and CORE Coat™ fromDanish Technological Institute (DTI) (including sol-gel coatings underthe tradenames CC010™, CC020™, and CC030™), or any combination thereof.At least one of these entities also offers services to apply acoating(s).

The downhole fluid lifting equipment is not limited to ESPs, and forexample, a hydraulic submersible pump, gas lift equipment, or otherlifting equipment may be utilized in some embodiments. The rate of flowof fluids through the production wellbores 30, 34 and the injectionwellbore 32 may be limited by the fluid handling capacities of thesurface facilities. Furthermore, while the control devices 54, 56, 60are illustrated above surface in FIG. 2, control devices can also bepositioned downhole to control the flow of fluids injected into orreceived from each of the hydrocarbon-bearing zones 22, 24.

The production wellbores 30, 34 may also include tubings 62, 68 foradding concentration of viscosity reducers 74, 78 into the productionwellbores 30, 34. The viscosity reducers 74, 78 may be stored in one ormore storage tanks on the surface 40 and pumped down the tubings 62, 68using one or more pumps on the surface 40. For example, a storage tankmay be utilized for the viscosity reducer 74 and a different storagetank may be utilized for the viscosity reducer 78, or alternatively, acommon storage tank may be utilized for both the viscosity reducers 74,78. Similarly, a pump may be utilized for the viscosity reducer 74 and adifferent pump may be utilized for the viscosity reducer 78, oralternatively, a common pump may be utilized for both the viscosityreducers 74, 78. The tubings 62, 68 may be new tubing, existing tubing,or any combination thereof. For example, any existing tubing alreadylocated in the production wellbores 30, 34, such as to inject acorrosion inhibitor or a scale inhibitor, may be utilized to add theviscosity reducers 74, 78 into the production wellbores 30, 34. Thetubings 62, 68 may be ⅛ inch to ½ inch in diameter. As illustrated,outlets of the tubings 62, 68 may be positioned towards the bottom ofthe production wellbores 30, 34 so that the viscosity reducers 74, 78exit the outlets prior to any downhole fluid lifting equipment (e.g.,the ESPs 64, 70) in the production wellbores 30, 34. The viscosityreducers 74, 78 may be added towards the bottom of the productionwellbores 30, 34 regardless of the location of the ESPs 64, 70. In someembodiments, the tubings 62, 68 (and outlets of the tubings 62, 68) maybe positioned in a different location than illustrated in FIG. 2. Thetubings 62, 68 should be long enough to position the outlets in thedesired locations in the production wellbores 30, 34.

FIG. 3 is a more detailed view of the system of FIG. 2, including a moredetailed view of the surface fluid processing equipment 41 on thesurface 40. For simplicity, FIG. 3 will focus on the production wellbore30, but the same discussion applies to the production wellbore 34. FIG.3 will focus on some possible places for the first location and thesecond location. Of note, in FIG. 3, the wellhead and other componentsillustrated after the wellhead may be coupled as illustrated in FIG. 3via surface piping (sometimes referred to as flowline(s) or pipe(s)) toaccomplish the fluid flow illustrated in FIG. 3.

As illustrated in FIGS. 2-3, the concentration of the viscosity reducer74 may be added to the fluid 76 being produced by the productionwellbores 30 at a first location 200 prior to any downhole fluid liftingequipment, such as prior to the ESP 64, in the production wellbore 30via the tubing 62 for complete chemical degradation of the polymerpresent in the fluid 76. The first location 200 is in the vicinity ofthe outlet of the tubing 62 prior to the ESP 64. In some embodiments,the residence time of the viscosity reducer 74 in the fluid 76 forcomplete chemical degradation of the polymer is 10 minutes or less. Thefluid 76 with the viscosity reducer 74, and with polymer that is on itsway to complete chemical degradation or already undergone completechemical degradation depending on the residence time of the viscosityreducer 74, flows up the production wellbore 30 through the ESP 64towards the wellhead 53. Consistent with this disclosure, completechemical degradation of the polymer in the fluid 76 may lead to less orno polymer scaling on the ESP 64. The concentration of the viscosityreducer 74 to be added may be determined through experiments in alaboratory setting as explained further hereinabove. Of note, theviscosity reducer may be added at the first location 200, or otherdownhole location, in the production wellbore 30 even if the productionwellbore 30 did not include the ESP 64.

As illustrated in FIGS. 2-3, the fluid 76 with the viscosity reducer 74flows from the wellhead 53 to at least one of the surface fluidprocessing equipment 41 on the surface 40 through surface piping. Forexample, the surface fluid processing equipment 41 comprises a FWKO 215,and the wellhead 53 and the FWKO 215 are coupled via surface piping. Aconcentration of neutralizer 205 is added to the fluid 76 being producedthrough the wellhead 53 at a second location 210 to neutralize theviscosity reducer 74 in the fluid 76. The second location 210 isupstream of the FWKO 215, in other words, the second location 210 isbefore the FWKO 215. In some embodiments, the residence time of theneutralizer 205 in the fluid 76 for complete neutralization of allexcess viscosity reducer 74 in the fluid 76 is 10 minutes or less.

The neutralizer 205 may be stored in a storage tank on the surface 40and added to the fluid 76 at the second location 210 using at least onedosing pump and at least one injection quill into the pipe coupling thewellhead 53 to the FWKO 215. For example, the quill (e.g., secondinjection apparatus) may penetrate about halfway through the pipe andabout perpendicular to the flow stream to facilitate mixing of theneutralizer 205 with the fluid 76. The neutralizer 205 may mix with thefluid 76 without a mixer. The neutralizer 205 will cause completeneutralization of all excess viscosity reducer 74 in the fluid 76 priorto the fluid 76 reaching the FWKO 215. The concentration of theneutralizer 205 to be added may be determined through experiments in alaboratory setting as explained further hereinabove. The concentrationof the viscosity reducer 74 discussed hereinabove and the concentrationof the neutralizer 205 may be added continuously to the fluid 76.

The first location 200 (where the viscosity reducer 74 is added) issufficiently upstream of the second location 210 (where the neutralizer205 is added) to allow for complete chemical degradation of the polymerprior to the fluid 76 reaching the second location 210. The secondlocation 210 is sufficiently upstream of any surface fluid processingequipment 41, such as the FWKO 215, to allow for complete neutralizationof all excess viscosity reducer 74 in the fluid 76 prior to the fluid 76reaching any surface fluid processing equipment 41. Consistent with thisdisclosure, complete neutralization of the excess viscosity reducer 74may lead to less or no corrosion of the surface fluid processingequipment 41 by the viscosity reducer 74.

As illustrated in FIGS. 2-3, the fluid 76 with the neutralizer 205(excess neutralizer) flows to the FWKO 215 to separate the water and thehydrocarbons (oil) of the fluid 76. Consistent with this disclosure,complete neutralization of the excess viscosity reducer 74 and completechemical degradation of the polymer may lead to less or no impact ofviscosity on the FWKO 215.

As illustrated in FIGS. 2-3, the surface fluid processing equipment 41comprises a HX 220 downstream of the FWKO 215, and the second location210 is upstream of the FWKO 215. The FWKO 215 and the HX 220 are coupledvia surface piping. The fluid 76, primarily the hydrocarbons, flow fromthe FWKO 215 through the HX 220 to heat the fluid 76. Consistent withthis disclosure, complete neutralization of the excess viscosity reducer74 and complete chemical degradation of the polymer may lead to less orno polymer scale on the HX 220. Furthermore, consistent with thisdisclosure, complete neutralization of the excess viscosity reducer 74and complete chemical degradation of the polymer may lead to less or nooil scale on the HX 220.

Of note, the HX 220 may be operated at a temperature that is 150 degreesCelsius or less (e.g., 145 degrees Celsius or less, 140 degrees Celsiusor less, 135 degrees Celsius or less, 130 degrees Celsius or less, 125degrees Celsius or less, 120 degrees Celsius or less, 115 degreesCelsius or less, 110 degrees Celsius or less, 105 degrees Celsius orless, 100 degrees Celsius or less, 95 degrees Celsius or less, 90degrees Celsius or less, 85 degrees Celsius or less, 80 degrees Celsiusor less, 75 degrees Celsius or less, 70 degrees Celsius or less, 65degrees Celsius or less, 60 degrees Celsius or less, 55 degrees Celsiusor less, 50 degrees Celsius or less, 45 degrees Celsius or less, 40degrees Celsius or less, 35 degrees Celsius or less, 30 degrees Celsiusor less, 25 degrees Celsius or less, 20 degrees Celsius or less, 15degrees Celsius or less, 10 degrees Celsius or less, 5 degrees Celsiusor less). In one embodiment, the HX 220 may be operated at a temperaturethat is at least 1 degrees Celsius (e.g., at least 5 degrees Celsius, atleast 10 degrees Celsius, at least 15 degrees Celsius, at least 20degrees Celsius, at least 25 degrees Celsius, at least 30 degreesCelsius, at least 35 degrees Celsius, at least 40 degrees Celsius, atleast 45 degrees Celsius, at least 50 degrees Celsius, at least 55degrees Celsius, at least 60 degrees Celsius, at least 65 degreesCelsius, at least 70 degrees Celsius, at least 75 degrees Celsius, atleast 80 degrees Celsius, at least 85 degrees Celsius, at least 90degrees Celsius, at least 95 degrees Celsius, at least 100 degreesCelsius, at least 105 degrees Celsius, at least 110 degrees Celsius, atleast 115 degrees Celsius, at least 120 degrees Celsius, at least 125degrees Celsius, at least 130 degrees Celsius, at least 135 degreesCelsius, at least 140 degrees Celsius, or at least 145 degrees Celsius).In one embodiment, the HX 220 may be operated at a temperature range of1 degrees Celsius to 150 degrees Celsius, 40 degrees Celsius to 140degrees Celsius, 80 degrees Celsius to 135 degrees Celsius, 1 degreeCelsius to 140 degrees Celsius, 4 degrees Celsius to 140 degreesCelsius, or 80 degrees Celsius to 140 degrees Celsius. The temperatureranges from any of the minimum values described above to any of themaximum values described above. The temperature of the HX 220 may dependon the specifics of the fluid 76 being produced via the productionwellbore 30, the specifics of the hydrocarbons, etc.

In some embodiments, at least a portion of the HX may be coated with acoating to reduce polymer adherence. In some embodiments, at least aportion of the HX which is in contact with fluid during operation iscoated with a coating to reduce polymer adherence. In certainembodiments, substantially all of the HX which is in contact with fluidduring operation is coated with a coating to reduce polymer adherence.In some embodiments, the heat exchanger comprises a plurality of plates(such as, but not limited to, plate and frame heat exchangers or plateand shell heat exchangers), and at least one of these plates may becoated with the coating to reduce polymer adherence. In someembodiments, the heat exchanger comprises a plurality of tubes (such as,but not limited to, shell and tube heat exchangers), and at least one ofthese tubes may be coated with the coating to reduce polymer adherence.When present, the coating can be any of the coatings described abovewith respect to the ESP.

As illustrated in FIGS. 2-3, the surface fluid processing equipment 41comprises a separator 225 downstream of the HX 220, and the secondlocation 200 is upstream of the FWKO 215. The HX 220 and the separator225 are coupled via surface piping. The fluid 76, primarily thehydrocarbons, flow from the HX 220 through the separator 225 to furtherseparate the water and the hydrocarbons. Consistent with thisdisclosure, complete neutralization of the excess viscosity reducer 74and complete chemical degradation of the polymer may lead to less or noimpact of viscosity on the separator 225. Furthermore, consistent withthis disclosure, complete neutralization of the excess viscosity reducer74 and complete chemical degradation of the polymer may lead to less orno polymer scale on the separator 225.

As illustrated in FIGS. 2-3, the hydrocarbons from the separator 225flow via surface piping to a Lease Automatic Custody Transfer unit(LACT) 230 for sale and other activities. Consistent with thisdisclosure, complete neutralization of the excess viscosity reducer 74and complete chemical degradation of the polymer may lead to less or nowater in oil (WIO) emulsions in the LACT 230.

As illustrated in FIGS. 2-3, the surface fluid processing equipment 41comprises a flotation cell, an IGF apparatus, a hydrocyclone, a filter,or any combination thereof downstream of the FWKO 215, and the secondlocation 210 is upstream of the FWKO 215. These components may becoupled as illustrated in FIG. 3 via surface piping to handle primarilythe water of the fluid 76. A flotation cell 235, an IGF apparatus 240, ahydrocyclone 245, or any combination thereof may be utilized to removesolids and any remaining hydrocarbons from the water of the fluid 76.For example, the water of the fluid 76 from the FWKO 215, the separator225, or both may flow through a flotation cell 235. Consistent with thisdisclosure, complete neutralization of the excess viscosity reducer 74and complete chemical degradation of the polymer may lead to less or noimpact of viscosity on the flotation cell 235. Alternatively, forexample, the water of the fluid 76 from the FWKO 215, the separator 225,or both may flow through the IGF apparatus 240. Consistent with thisdisclosure, complete neutralization of the excess viscosity reducer 74and complete chemical degradation of the polymer may lead to less or noimpact of viscosity on the IGF apparatus 240. Alternatively, forexample, the water of the fluid 76 from the FWKO 215, the separator 225,or both may flow through the hydrocyclone 245. Consistent with thisdisclosure, complete neutralization of the excess viscosity reducer 74and complete chemical degradation of the polymer may lead to less or noimpact of drag-reducing on the hydrocyclone 245. Furthermore, consistentwith this disclosure, complete neutralization of the excess viscosityreducer 74 and complete chemical degradation of the polymer may lead toless or no oil in water emulsions in the water of the fluid 76 flowingout of the flotation cell 235, the IGF apparatus 240, and thehydrocyclone 245. In some embodiments, the water of the fluid 76 mayflow through two of these components or even flow through all three ofthese components.

As illustrated in FIGS. 2-3, the water of the fluid 76 flows from theflotation cell 235, the IGF apparatus 240, the hydrocyclone 245, or anycombination thereof via surface piping through a filter 260 to removeany remaining solids. Consistent with this disclosure, completeneutralization of the excess viscosity reducer 74 and complete chemicaldegradation of the polymer may lead to less or no membrane fouling ofthe filter 260.

As illustrated in FIGS. 2-3, the water of the fluid 76 flows from thefilter 260 to re-injection 265, discharge 270, polymer mixing 275, orany combination thereof. Regarding re-injection 265, the water of thefluid 76 may be injected into the hydrocarbon-bearing formation 20(e.g., via the injection wellbore 32 or different injection wellbore), adifferent hydrocarbon-bearing formation via a different injectionwellbore, or any combination thereof. Regarding discharge 270, the waterin the fluid 76 may be discharged as permitted by law.

Regarding polymer mixing 275, a concentration of additional polymer 280may be added to the water of the fluid 76 to increase the viscosity ofthe water of the fluid 76. For example, the additional polymer may beadded at a third location (e.g., after the filter 260) that isdownstream of the second location. For instance, after the filter 260,the water of the fluid 76 may return to a main water line and theadditional polymer 280 may mixed in with the water of the fluid 76 tocreate more fluid 57 for injection (discussed in FIG. 2). Thus, thethird location may be the location where polymer is mixed in at thesurface 40, such as where at least one mixer is located for mixingpolymer, for this EOR process. The same or similar polymer mixing designutilized for the fluid 57 injected into the injection wellbore 32 thatwas used at the start of the EOR process may be utilized at polymermixing 275, as explained further hereinabove. For example, polymermixing 275 may include mixing the same synthetic polymer (with sameconstituents and same concentrations) in the same manner as the fluid 57injected into the injection wellbore 32. However, in some embodiments,polymer mixing 275 may include making at least one change, such as, butnot limited to, changing a constituent or concentration of the polymer,to improve hydrocarbon recovery. The polymer mixing 275 may be performedin a manner different than at the start of the EOR process.

The water of the fluid 76 with the increased viscosity may be injectedinto the hydrocarbon-bearing formation 20 (e.g., via the injectionwellbore 32), a different hydrocarbon-bearing formation via a differentinjection wellbore, or any combination thereof, as discussed withre-injection 265.

FIG. 4 illustrates the system of FIG. 3 with a different first locationand a different second location. In FIG. 4, the viscosity reducer 74 isadded at a first location 285 instead of the first location 200 of FIG.3. The first location 285 of FIG. 4 is downstream of the wellhead 53 ofthe production wellbore 30. In FIG. 4, the neutralizer 205 is added at asecond location 290 instead of the second location 210 of FIG. 3. Thesecond location 290 of FIG. 4 is downstream of the wellhead 53 of theproduction wellbore 30. The first location 285 and the second location290 are upstream of the FWKO 215. The first location 285 (where theviscosity reducer 74 is added) is sufficiently upstream of the secondlocation 290 (where the neutralizer 205 is added) to allow for completechemical degradation of the polymer prior to the fluid 76 reaching thesecond location 290. The second location 290 is sufficiently upstream ofany surface fluid processing equipment 41, such as the FWKO 215, toallow for complete neutralization of all excess viscosity reducer 74 inthe fluid 76 prior to the fluid 76 reaching any surface fluid processingequipment 41. Consistent with this disclosure, complete neutralizationof the excess viscosity reducer 74 and complete chemical degradation ofthe polymer may lead to less or no corrosion of the surface fluidprocessing equipment 41, as well as other advantageous discussed in thecontext of FIG. 3.

The viscosity reducer 74 may be stored in a storage tank on the surface40 and added to the fluid 76 at the first location 285 using at leastone dosing pump and at least one injection quill into the pipe couplingthe wellhead 53 to the FWKO 215. For example, the quill (e.g., firstinjection apparatus) may penetrate about halfway through the pipe andabout perpendicular to the flow stream to facilitate mixing of theviscosity reducer 74 with the fluid 76. The viscosity reducer 74 may mixwith the fluid 76 without a mixer. The viscosity reducer 74 will causecomplete degradation of the polymer in the fluid 76 prior to the fluid76 reaching the second location 290 where the neutralizer 205 is added.The concentration of the viscosity reducer 74 to be added may bedetermined through experiments in a laboratory setting as explainedfurther hereinabove. The concentration of the viscosity reducer 74 (andthe concentration of the neutralizer, discussed further hereinbelow) maybe added continuously to the fluid 76.

Similarly, the neutralizer 205 may be stored in a storage tank on thesurface 40 and added to the fluid 76 at the second location 290 using atleast one dosing pump and at least one injection quill into the pipecoupling the wellhead 53 to the FWKO 215, as explained hereinabove inthe context of the second location 210 in FIG. 3. The neutralizer 205will cause complete neutralization of all excess viscosity reducer 74 inthe fluid 76 prior to the fluid 76 reaching the FWKO 215. Theconcentration of the neutralizer 205 to be added may be determinedthrough experiments in a laboratory setting as explained furtherhereinabove.

Indeed, the viscosity reducer may be added at practically any locationdownhole in the production wellbore or practically any location on thesurface as long as the location satisfies the criteria (a)-(b).Similarly, the neutralizer may be added at practically any locationdownhole in the production wellbore or practically any location on thesurface as long as the location satisfies the criteria (a)-(b). In someembodiments, the first location may even represent a plurality oflocations such that the viscosity reducer is added at multiple locationsand/or the second location may even represent a plurality of locationssuch that the neutralizer is added at multiple locations as long as thecriteria (a)-(b) is satisfied.

Furthermore, those of ordinary skill in the art will appreciate thatother modifications may be made to the systems illustrated in FIGS. 3-4.For example, the separator 225 may be positioned upstream of the FWKO215 if the fluid 76 being produced via the production wellbore 30 isexpected to contain a lot more hydrocarbons than water. The FWKO 215 maybe upstream of the separator 225 (as in FIGS. 3-4) if the fluid 76 beingproduced via the production wellbore 30 is expected to contain a lotmore water than hydrocarbons.

Example 1: Sodium hypochlorite (NaOCl), the viscosity reducer, may beeffective in purifying water on a large scale. Sodium hypochloritedissolved in water ionizes into the highly oxidative hypochlorous acid(HOCl) and less active hypochlorite ion (OCl—). The pH controls theabundance of each species. No pH modification was used for theseexperiments. The concentration of sodium hypochlorite caused the powderpolymer X to undergo complete chemical degradation, which is indicatedby the viscosity of <1 cp for the brine. Indeed, the viscosity of thebrine having powder polymer X returned to the viscosity of thepolymer-free version of that brine due to the viscosity reducer ofNaOCL. As indicated herein, a viscosity of less than 1.4 cp for thebrine indicates complete chemical degradation of the polymer.

In this Example 1, powder polymer X was hydrated for 24 hours in brineto yield a concentration of 10,000 ppm. The solution was diluted with73:27 brine to a concentration of 2,000 ppm (typical dosage of polymerfor CEOR). The solution was allowed to stir at 400 rpm for a period of 2hours to fully hydrate the diluted polymer. To 20 mL of polymersolution, 0.125 uL of 7.85% NaOCl was added. As polymer degrade, theviscosity is reduced to less than 1 cp. The viscosity was measured as afunction of time on a Brookfield DV-E LV with UL adapter at 25° C. Theresults of the study is provided in Table 2 below:

TABLE 2 Viscosity of 2000 ppm of powder polymer in 73:27 brine treatedwith 7.85% NaOCl as a function of time Conc, Polymer, NaOCl NaOCl, Time,Polymer ppm mL wt % uL RPM min Visc, cp Powder 2000 20 — — 6 0 31.9polymer X Powder 2000 20 7.85 0.125 6 3 <1 polymer X

Example 2: FIG. 5 is a plot illustrating a viscosity reduction example.More specifically, FIG. 5 is a plot illustrating a reduction inviscosity in three samples as a function of time. The viscosity reducerin these three samples is sodium hypochlorite (NaOCl). These threesamples were prepared using fluid being produced from an activeproduction wellbore and the water in these three samples is brine. Thesample corresponding with the curve having the x's has a ratio ofpolymer concentration to viscosity reducer concentration of 1:1. Thesample corresponding with the curve having the squares has a ratio ofpolymer concentration to viscosity reducer concentration of 2:1. Thesample corresponding with the curve having the diamonds has a ratio ofthe polymer to the viscosity reducer is 4:1 by concentration.Hydrocarbons were not present in the samples. The polymer in these threesamples is HPAM. The polymer is present because the three sample includebrine being produced that includes polymer, but it is also contemplatedin this disclosure that representative synthetic samples may be createdand polymer may be added to the synthetic samples.

As discussed hereinabove, complete chemical degradation of the polymermay be detected indirectly when the viscosity of the water decreases tothe viscosity of the polymer-free version of that water (brine in thesethree samples). FIG. 5 illustrates that the viscosity of the curves withthe squares and the x's decreased to about 1 cp at 20° C. in response tothe addition of the viscosity reducer. A viscosity of about 1 cp at 20°C. is consistent with the viscosity of polymer-free brine. Thus, thepolymer corresponding to the curves with the squares and the x's hasundergone complete chemical degradation in response to the addition ofthe viscosity reducer. As indicated herein, a viscosity of less than 1.4cp for the brine indicates complete chemical degradation of the polymer.

Of note: The curve with the diamonds does illustrate a reduction inviscosity, but the viscosity at 15 minutes is higher than the viscosityof the other two curves at 15 minutes of about 1 cp at 20° C. The higherviscosity of the curve with the diamonds potentially indicates that ahigher concentration of the viscosity reducer is needed for the higherconcentration of polymer in order to reduce the viscosity to that ofpolymer-free brine, or a measurement error occurred.

Example 3: FIG. 6 is a plot illustrating a viscosity reducer example.More specifically, FIG. 5 illustrates a normalized viscosity reducerconcentration added to a sample and the reaction of the normalizedviscosity reducer concentration with a polymer concentration as afunction of time. The viscosity reducer in this sample is sodiumhypochlorite (NaOCl). This sample was prepared using fluid beingproduced from an active production wellbore and the water in this sampleis brine. The polymer in this sample is HPAM. The ratio of the polymerto the viscosity reducer is 1:1 by concentration.

In FIG. 6, for every part of viscosity reducer added, about 90% of theviscosity reducer is used up in the reaction. About 10% of theconcentration of the viscosity reducer remains in the sample as excessviscosity reducer based on titration. As discussed hereinabove, theexcess viscosity reducer will undergo complete neutralization with aconcentration of neutralizer.

Example 4: FIG. 7 is a plot illustrating a neutralizer example. Morespecifically, FIG. 7 illustrates a normalized neutralizer concentrationadded to a sample and the reaction of the normalized neutralizerconcentration with a normalized viscosity reducer concentration. FIG. 7also illustrates the amount of excess neutralizer remaining in thesample after the reaction via titration at ambient temperature. Theviscosity reducer in this sample is sodium hypochlorite (NaOCl). Thesample was prepared using fluid being produced from an active productionwellbore and the water in this sample is brine. The neutralizer in thissample is sodium thiosulfate. The curve with the diamonds indicates thatthe normalized viscosity reducer concentration is 1.00 in the sample.The curve with the triangles indicates that the normalized neutralizeris 3.1 in the sample. The ratio of the viscosity reducer to theneutralizer is 1:3.3 by concentration.

In FIG. 7, the curve with the circles indicates that the neutralizerreacted with the viscosity reducer as illustrated in the secondaryy-axis on the right. The curve with the squares indicates that excessneutralizer remained, determined through titration, as illustrated inthe secondary y-axis on the right. The presence of the excessneutralizer indicates that the viscosity reducer has undergone completeneutralization.

Example 5: FIG. 8 is a plot illustrating another viscosity reductionexample. More specifically, FIG. 8 is a plot illustrating a reduction inviscosity in five samples as a function of time. The viscosity reducerin these five samples is tetrakis(hyroxymethyl)-phosphonium sulfate(THPS). Sodium thiosulfate was used as a neutralizer to arrest thereactions. The three curves with squares and diamonds, corresponding to50 ppm THPS, 100 THPS, and 250 ppm THPS, indicate that the viscosity ofthe sample returned to a viscosity of polymer-free water of less than1.4 cp.

Example 6: FIG. 9 illustrates that approximately 7 minutes after theaddition of 100 ppm of sodium hypochlorite, which is the viscosityreducer, the control showed approximately 300 ppm of oil in water (OIW)and the sample showed less than 70 ppm of OIW.

Example 7: In FIG. 10, an absence of any gelling is observed in thesample containing approximately 100 ppm of sodium hypochlorite, which isthe viscosity reducer. The control and the sample were heated at 120° C.for 60 h.

In conclusion, following injection of various chemicals slugs in an EORprocess, polymer is often produced with the oil and other injectedchemicals, and frequently forms emulsions. Given the high viscosity ofthe polymer-rich fluid being produced via the production wellbore,higher concentrations of oil are entrapped. Furthermore, polymershearing by electrical submersible pumps (ESP's), can create strongemulsions with high volumes of trapped oil. Traditional methods of waterclarification using polymer-based flocculants are targeted to remove oilparticulates that can adhere to the polymers. In some instances, thepolymers are even tailored to specific oils. However, for polymerflooding, these polymers compete with the partially hydrolyzedpolyacrylamide (HPAM's) that are sometimes used for EOR. The basicbackbone for many water-soluble polymers is polyacrylamide and henceaddition of specifically tailored polymers does not improve separation.It also does not address the driving force, i.e. the enhanced viscosityof produced polymer, which traps the oil. Other negative impacts, suchas polymer scaling and membrane fouling, are also discussed. Providedherein are embodiments of systems and methods where the polymerundergoes complete chemical degradation using the viscosity reducer.Furthermore, the excess viscosity reducer undergoes completeneutralization using a neutralizer. By doing so, the fluid (e.g., theseparated water of the fluid) may be made more suitable or suitable forre-injection, discharge, additional polymer mixing, or any combinationthereof. Furthermore, in some embodiments, once the viscosity islowered, additional emulsion breakers may also be utilized to readilytarget the oil-water interfaces due to reduced viscosity and rapidlyinduce separation.

The description and illustration of one or more embodiments provided inthis application are not intended to limit or restrict the scope of theinvention as claimed in any way. The embodiments, examples, and detailsprovided in this disclosure are considered sufficient to conveypossession and enable others to make and use the best mode of claimedinvention. The claimed invention should not be construed as beinglimited to any embodiment, example, or detail provided in thisapplication. Regardless whether shown and described in combination orseparately, the various features (both structural and methodological)are intended to be selectively included or omitted to produce anembodiment with a particular set of features. Having been provided withthe description and illustration of the present application, one skilledin the art may envision variations, modifications, and alternateembodiments falling within the spirit of the broader aspects of theclaimed invention and the general inventive concept embodied in thisapplication that do not depart from the broader scope. For instance,such other examples are intended to be within the scope of the claims ifthey have structural or methodological elements that do not differ fromthe literal language of the claims, or if they include equivalentstructural or methodological elements with insubstantial differencesfrom the literal languages of the claims, etc. All citations referredherein are expressly incorporated herein by reference.

1. A method of treating fluid comprising hydrocarbons, water, andpolymer being produced from a hydrocarbon-bearing formation via aproduction wellbore, the method comprising: adding a concentration of aviscosity reducer to the fluid to degrade the polymer present in thefluid; and adding a concentration of a neutralizer to the fluid toneutralize the viscosity reducer in the fluid; wherein: the addition ofthe concentration of the viscosity reducer is in a sufficient quantityto allow for complete chemical degradation of the polymer prior to theaddition of the concentration of the neutralizer in the fluid such thatexcess viscosity reducer is present in the fluid; and the addition ofthe concentration of the neutralizer is sufficiently upstream of anysurface fluid processing equipment to allow for complete neutralizationof the excess viscosity reducer such that excess neutralizer is presentin the fluid prior to the fluid reaching any of the surface fluidprocessing equipment.
 2. The method of claim 1, wherein the viscosityreducer is in the fluid for 10 minutes or less to allow for completechemical degradation of the polymer.
 3. The method of any of claims 1-2,wherein the neutralizer is in the fluid for 10 minutes or less to allowfor complete neutralization of the excess viscosity reducer.
 4. Themethod of any of claims 1-3, wherein the concentration of the viscosityreducer is 10 ppm to 1,500 ppm.
 5. The method of any of claims 1-4,wherein the concentration of the neutralizer is 25 ppm to 7,500 ppm. 6.The method of any of claims 1-5, wherein the viscosity reducer is addedin a ratio of the polymer to the viscosity reducer of 1:1 to 5:1 byconcentration.
 7. The method of any of claims 1-6, wherein theneutralizer is added in a ratio of the excess viscosity reducer to theneutralizer of 1:2.5 to 1:5 by concentration.
 8. The method of any ofclaims 1-7, wherein the viscosity reducer comprises sodium hypochlorite,sodium chlorite, hydrogen peroxide, Fenton's reagent, potassiumpermanganate, fluorine, hydroxyl radical, atomic oxygen, ozone,perhydroxyl radical, hypobromous acid, chlorine dioxide, hypochlorousacid, hypoiodous acid, chlorine, bromine, iodine,tetrakis(hyroxymethyl)-phosphonium sulfate, sodium persulfate, or anycombination thereof.
 9. The method of any of claims 1-8, wherein theviscosity reducer is a non-sulfur containing viscosity reducer.
 10. Themethod of any of claims 1-9, wherein the non-sulfur containing viscosityreducer comprises sodium hypochlorite, sodium chlorite, hydrogenperoxide, Fenton's reagent, potassium permanganate, fluorine, hydroxylradical, atomic oxygen, ozone, perhydroxyl radical, hypobromous acid,chlorine dioxide, hypochlorous acid, hypoiodous acid, chlorine, bromine,iodine, or any combination thereof.
 11. The method of any of claims1-10, wherein the neutralizer comprises ascorbic acid, sodium ascorbate,citric acid, sodium thiosulfate, sodium metabisulfite, or anycombination thereof.
 12. The method of any of claims 1-11, wherein theneutralizer is a non-sulfur containing neutralizer.
 13. The method ofany of claims 1-12, wherein the non-sulfur containing neutralizercomprises ascorbic acid, sodium ascorbate, citric acid, or anycombination thereof.
 14. The method of any of claims 1-13, furthercomprising: passing the fluid through the surface fluid processingequipment to separate the hydrocarbons and the water; adding aconcentration of additional polymer to the separated water to increasethe viscosity of the separated water; and injecting the separated waterwith the increased viscosity into the hydrocarbon-bearing formation, adifferent hydrocarbon-bearing formation, or any combination thereof. 15.The method of any of claims 1-14, wherein the surface fluid processingequipment comprises a free water knockout, a heat exchanger, aseparator, a flotation cell, an induced gas flotation apparatus, ahydrocyclone, a filter, or any combination thereof.
 16. The method ofclaim 15, wherein at least a portion of the heat exchanger is coatedwith a coating to reduce polymer adherence.
 17. The method of claim 16,wherein the coating has a thickness of from 5 microns to 120 microns.18. The method of any of claims 16-17, wherein the coating comprisesfrom one to three layers.
 19. The method of any of claims 16-18, whereinthe coating comprises an organic-inorganic hybrid coating, afluoropolymer coating, or any combination thereof.
 20. The method of anyof claims 1-19, wherein the concentration of the viscosity reducer isadded at a first location, and wherein the concentration of theneutralizer is added at a second location.
 21. The method of any ofclaims 1-20, wherein the first location is prior to any downhole fluidlifting equipment in the production wellbore.
 22. The method of any ofclaims 1-21, wherein the downhole fluid lifting equipment comprises anelectrical submersible pump, a hydraulic submersible pump, gas liftequipment, or any combination thereof.
 23. The method of claim 22,wherein at least a portion of the electric submersible pump is coatedwith a coating to reduce polymer adherence.
 24. The method of claim 23,wherein the coating has a thickness of from 5 microns to 120 microns.25. The method of any of claims 23-24, wherein the coating comprisesfrom one to three layers.
 26. The method of any of claims 23-25, whereinthe coating comprises an organic-inorganic hybrid coating, afluoropolymer coating, or any combination thereof.
 27. The method of anyof claims 1-26, wherein the first location is downstream of a wellheadof the production wellbore.
 28. The method of any of claims 1-27,wherein the surface fluid processing equipment comprises a free waterknockout, and the second location is upstream of the free waterknockout.
 29. The method of any of claims 1-28, wherein the surfacefluid processing equipment comprises a heat exchanger downstream of thefree water knockout, and the second location is upstream of the freewater knockout.
 30. The method of any of claims 1-29, wherein thesurface fluid processing equipment comprises a separator downstream ofthe heat exchanger, and the second location is upstream of the freewater knockout.
 31. The method of any of claims 1-30, wherein thesurface fluid processing equipment comprises a flotation cell, aninduced gas flotation apparatus, a hydrocyclone, a filter, or anycombination thereof downstream of the free water knockout, and thesecond location is upstream of the free water knockout.
 32. The methodof any of claims 1-31, wherein the first location and the secondlocation are upstream of the free water knockout.
 33. The method of anyof claims 1-32, wherein the first location is sufficiently upstream ofthe second location to allow for complete chemical degradation of thepolymer prior to the fluid reaching the second location, and wherein thesecond location is sufficiently upstream of any of the surface fluidprocessing equipment to allow for complete neutralization of the excessviscosity reducer in the fluid prior to the fluid reaching any of thesurface fluid processing equipment.
 34. The method of any of claims1-33, wherein the concentration of the viscosity reducer and theconcentration of the neutralizer are added continuously to the fluid.35. The method of any of claims 1-34, wherein the fluid has a viscosityof less than 1.4 cp with a minimum viscosity of 0.9 cp after separationof at least some of the hydrocarbons from the fluid by the surface fluidprocessing equipment.
 36. The method of any of claims 1-35, furthercomprising determining the concentration of the viscosity reducer to addto the fluid for complete chemical degradation of the polymer by usingat least one hydrocarbon-free sample representative of the fluid,wherein determining the concentration of the viscosity reducer comprisescausing the at least one sample to return to having a polymer-freeviscosity, causing the at least one sample to have a viscosity of lessthan 1.4 cp with a minimum of 0.9 cp, causing excess viscosity reducerto be present in the at least one sample, or any combination thereof.37. The method of any of claims 1-36, further comprising determining theconcentration of the neutralizer to add to the fluid for completeneutralization of the excess viscosity reducer in the fluid by using atleast one hydrocarbon-free sample representative of the fluid, whereindetermining the concentration of the neutralizer comprises causingexcess neutralizer to be present in the at least one sample.
 38. Themethod of any of claims 1-37, wherein determining the concentration ofthe viscosity reducer, the concentration of the neutralizer, or bothcomprises using a viscometer, titration, gel permeation chromatography,or any combination thereof.
 39. A system of treating fluid, the systemcomprising: a production wellbore for producing fluid comprisinghydrocarbons, water, and polymer from a hydrocarbon-bearing formation; afirst injection apparatus for adding a concentration of a viscosityreducer to the fluid to degrade the polymer present in the fluid; asecond injection apparatus for adding a concentration of a neutralizerto the fluid to neutralize the viscosity reducer in the fluid; andsurface fluid processing equipment for separating the hydrocarbons fromthe fluid; wherein: the addition of the concentration of the viscosityreducer is in a sufficient quantity to allow for complete chemicaldegradation of the polymer prior to the addition of the concentration ofthe neutralizer in the fluid such that excess viscosity reducer ispresent in the fluid; and the addition of the concentration of theneutralizer is sufficiently upstream of any of the surface fluidprocessing equipment to allow for complete neutralization of the excessviscosity reducer such that excess neutralizer is present in the fluidprior to the fluid reaching any of the surface fluid processingequipment.
 40. The system of claim 39, wherein the viscosity reducer isin the fluid for 10 minutes or less to allow for complete chemicaldegradation of the polymer.
 41. The system of any of claims 39-40,wherein the neutralizer is in the fluid for 10 minutes or less to allowfor complete neutralization of the excess viscosity reducer.
 42. Thesystem of any of claims 39-41, wherein the concentration of theviscosity reducer is 10 ppm to 1,500 ppm.
 43. The system of any ofclaims 39-42, wherein the concentration of the neutralizer is 25 ppm to7,500 ppm.
 44. The system of any of claims 39-43, wherein the viscosityreducer is added in a ratio of the polymer to the viscosity reducer of1:1 to 5:1 by concentration.
 45. The system of any of claims 39-44,wherein the neutralizer is added in a ratio of the excess viscosityreducer to the neutralizer of 1:2.5 to 1:5 by concentration.
 46. Thesystem of any of claims 39-45, wherein the viscosity reducer comprisessodium hypochlorite, sodium chlorite, hydrogen peroxide, Fenton'sreagent, potassium permanganate, fluorine, hydroxyl radical, atomicoxygen, ozone, perhydroxyl radical, hypobromous acid, chlorine dioxide,hypochlorous acid, hypoiodous acid, chlorine, bromine, iodine,tetrakis(hyroxymethyl)-phosphonium sulfate, a biocide, sodiumpersulfate, or any combination thereof.
 47. The system of any of claims39-46, wherein the viscosity reducer is a non-sulfur containingviscosity reducer.
 48. The system of any of claims 39-47, wherein thenon-sulfur containing viscosity reducer comprises sodium hypochlorite,sodium chlorite, hydrogen peroxide, Fenton's reagent, potassiumpermanganate, fluorine, hydroxyl radical, atomic oxygen, ozone,perhydroxyl radical, hypobromous acid, chlorine dioxide, hypochlorousacid, hypoiodous acid, chlorine, bromine, iodine, or any combinationthereof.
 49. The system of any of claims 39-48, wherein the neutralizercomprises ascorbic acid, sodium ascorbate, citric acid, sodiumthiosulfate, sodium metabisulfite, or any combination thereof.
 50. Thesystem of any of claims 39-49, wherein the neutralizer is a non-sulfurcontaining neutralizer.
 51. The system of any of claims 39-50, whereinthe non-sulfur containing neutralizer comprises ascorbic acid, sodiumascorbate, citric acid, or any combination thereof.
 52. The system ofany of claims 39-51, wherein the fluid is passed through the surfacefluid processing equipment to separate the hydrocarbons and the water,and wherein a concentration of additional polymer is added to theseparated water to increase the viscosity of the separated water, andwherein the separated water with the increased viscosity is injectedinto the hydrocarbon-bearing formation, a different hydrocarbon-bearingformation, or any combination thereof.
 53. The system of any of claims39-52, wherein the surface fluid processing equipment comprises a freewater knockout, a heat exchanger, a separator, a flotation cell, aninduced gas flotation apparatus, a hydrocyclone, a filter, or anycombination thereof.
 54. The system of claim 53, wherein at least aportion of the heat exchanger is coated with a coating to reduce polymeradherence.
 55. The system of claim 54, wherein the coating has athickness of from 5 microns to 120 microns.
 56. The system of any ofclaims 54-55, wherein the coating comprises from one to three layers.57. The system of any of claims 54-56, wherein the coating comprises anorganic-inorganic hybrid coating, a fluoropolymer coating, or anycombination thereof.
 58. The system of any of claims 39-57, wherein theconcentration of the viscosity reducer is added at a first location, andwherein the concentration of the neutralizer is added at a secondlocation.
 59. The system of any of claims 39-58, wherein the firstlocation is prior to any downhole fluid lifting equipment in theproduction wellbore.
 60. The system of any of claims 39-59, wherein thedownhole fluid lifting equipment comprises an electrical submersiblepump, a hydraulic submersible pump, gas lift equipment, or anycombination thereof.
 61. The system of claim 60, wherein at least aportion of the electric submersible pump is coated with a coating toreduce polymer adherence.
 62. The system of claim 61, wherein thecoating has a thickness of from 5 microns to 120 microns.
 63. The systemof any of claims 61-62, wherein the coating comprises from one to threelayers.
 64. The system of any of claims 61-63, wherein the coatingcomprises an organic-inorganic hybrid coating, a fluoropolymer coating,or any combination thereof.
 65. The system of any of claims 39-64,wherein the first location is downstream of a wellhead of the productionwellbore.
 66. The system of any of claims 39-65, wherein the surfacefluid processing equipment comprises a free water knockout, and thesecond location is upstream of the free water knockout.
 67. The systemof any of claims 39-66, wherein the surface fluid processing equipmentcomprises a heat exchanger downstream of the free water knockout, andthe second location is upstream of the free water knockout.
 68. Thesystem of any of claims 39-67, wherein the surface fluid processingequipment comprises a separator downstream of the heat exchanger, andthe second location is upstream of the free water knockout.
 69. Thesystem of any of claims 39-68, wherein the surface fluid processingequipment comprises a flotation cell, an induced gas flotationapparatus, a hydrocyclone, a filter, or any combination thereofdownstream of the free water knockout, and the second location isupstream of the free water knockout.
 70. The system of any of claims39-69, wherein the first location and the second location are upstreamof the free water knockout.
 71. The system of any of claims 39-70,wherein the first location is sufficiently upstream of the secondlocation to allow for complete chemical degradation of the polymer priorto the fluid reaching the second location, and wherein the secondlocation is sufficiently upstream of any of the surface fluid processingequipment to allow for complete neutralization of the excess viscosityreducer in the fluid prior to the fluid reaching any of the surfacefluid processing equipment.
 72. The system of any of claims 39-71,wherein the concentration of the viscosity reducer and the concentrationof the neutralizer are added continuously to the fluid.
 73. The systemof any of claims 39-72, wherein the fluid has a viscosity of less than1.4 cp with a minimum viscosity of 0.9 cp after separation of at leastsome of the hydrocarbons from the fluid by the surface fluid processingequipment.
 74. The system of any of claims 39-73, wherein theconcentration of the viscosity reducer to add to the fluid for completechemical degradation of the polymer is determined by using at least onehydrocarbon-free sample representative of the fluid, wherein determiningthe concentration of the viscosity reducer comprises causing the atleast one sample to return to having a polymer-free viscosity, causingthe at least one sample to have a viscosity of less than 1.4 cp with aminimum of 0.9 cp, causing excess viscosity reducer to be present in theat least one sample, or any combination thereof.
 75. The system of anyof claims 39-74, wherein the concentration of the neutralizer to add tothe fluid for complete neutralization of the excess viscosity reducer inthe fluid is determined by using at least one hydrocarbon-free samplerepresentative of the fluid, wherein determining the concentration ofthe neutralizer comprises causing excess neutralizer to be present inthe at least one sample.
 76. The system of any of claims 39-75 whereinthe concentration of the viscosity reducer, the concentration of theneutralizer, or both is determined by using a viscometer, titration,high gel permeation chromatography, or any combination thereof.